factory drilling: a lean manufacturing approach to ... · iii abstract drilling efficiency...
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Chair of Drilling Engineering and Well Completion
Master Thesis
Factory Drilling: A Lean Manufacturing Approach
to Drilling Operations
Written by: Advisor: William Duffy, BSc Univ.-Prof. Dipl.-Ing. Dr.mont. Gerhard Thonhauser m1135497
Leoben, 21.06.2016
i
EIDESSTATTLICHE ERKLÄRUNG
Ich erkläre an Eides statt, dass ich die vorliegende Diplomarbeit selbständig und ohne fremde Hilfe verfasst, andere als die angegebenen Quellen und Hilfsmittel nicht benutzt und die den benutzten Quellen wörtlich und inhaltlich entnommenen Stellen als solche erkenntlich gemacht habe.
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AFFIDAVIT
I hereby declare that the content of this work is my own composition and has not been submitted previously for any higher degree. All extracts have been distinguished using quoted references and all information sources have been acknowledged.
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Kurzfassung
Techniken zur Effizienzsteigerung werden in der Bohrindustrie erfolgreich eingesetzt um die Bohrkosten
zu reduzieren. Leider werden sie dennoch von Bohrkontraktoren vernachlässigt, obwohl deren Hauptziel
die Steigerung des Umsatzes ist. Wenn Operatoren Chancen zur Verbesserung nicht wahrnehmen,
können Ineffizienzen bei Bohroperationen überhandnehmen. Einige Firmen produzieren beispielsweise
die billigstmögliche Ausrüstung um die Kosten pro Bohrung zu reduzieren. Andere wiederum gehen so
weit und legen ihre Bohrungen unterhalb der Mindeststandards aus, wenn sie das Gefühl haben, dass
der Qualitätsverlust das Risiko und die gesparten Ausgaben rechtfertigt. Ineffizienzen und
minderwertige Auslegung versuchen jedoch so gut wie in allen Fällen eine Erhöhung der
Bohrungskosten, entweder sofort, in Form von langsamem Bohrfortschritt oder später im Lebenszyklus
der Bohrung, wenn die minderwertige Ausstattung versagt und teure Sondenbehandlungs- und
Reparaturarbeiten notwendig sind.
Das „Lean Manufacturing“ Konzept hat sich in vielen Industrien durchgesetzt um die Effizienz zu
optimieren und die Kosten zu senken. Vereinfacht gesagt, wird bei dieser Methode unnützer Ballast in
der Produktion beseitigt, während der Wert für den Kunden maximiert wird. Die Öl- und Gasindustrie
stellt hier keine Ausnahme dar, da auch hier mit diesem Konzept Lieferung und Kosten optimiert
werden, sei es bei Bohrungen im Fall von Operatoren oder bei Werkzeugen und Ausrüstung im Fall von
Servicefirmen. Auch das Bohren selbst kann durch dieses Verfahren optimiert werden, indem
Ineffizienzen beseitigt, die notwendigen Ressourcen reduziert, Kosten minimiert und die Qualität
beibehalten werden.
In Anerkennung der Tatsache, dass die Wirtschaftlichkeit von Projekten weltweit gesteigert werden
muss, hat sich eine der führenden Öl- und Gasfirmen dazu entschlossen eine Kampagne zu starten um in
sämtlichen Gebieten und Funktionen die Effizienz zu steigern und Kosten zu reduzieren um die
finanziellen Ziele zu erreichen. Diese Arbeit betrachtet, wie eine der Bohrmannschaften im
Unternehmen die Konzepte des „Lean Manufacturing“ übernommen hat und effektiv sowohl die Kosten
als ich die Zeit reduziert hat um eine Bohrung fertigzustellen.
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Abstract
Drilling efficiency optimization techniques are proven at reducing well costs. Unfortunately, they are
often neglected by operators, even when their primary focus is to maximize revenue. Inefficiencies can
inundate drilling campaigns, usually as a result of operator’s being blind to opportunity. To achieve well
cost reductions, some operators will procure the cheapest available equipment. Others will go as far as
designing their wells below minimum standards if they feel that the sacrifice in quality and specification
is worth the risk and money saved. Inefficiencies and sub-standard designs almost always cause
increased well costs, either right away, as the case is with slow drilling in typical day rate contract , or
later on in the well life cycle, when costly work overs and remedial operations are required when the
substandard equipment fails.
Lean manufacturing has been accepted across a wide array of industries as the most proven method for
optimizing efficiency and reducing operating cost. In essence, Lean is the elimination of waste while
maximizing value to the customer. The oil and gas industry is no exception as Lean has been
successfully used for improving product delivery and cost, whether its wells in the case of operators or
tools and equipment in the case of service providers. Drilling, a component of the overall well
construction process, can be optimized through Lean concepts by removing inefficiencies, reducing
required resources, minimizing costs and maintaining product quality.
In recognition of the need for improving project economics world-wide, a major international oil and gas
company instated a campaign to improve efficiency and reduce costs across all areas and function
groups to help meet financial goals. This paper reviews how one of the company’s drilling teams
adopted Lean methodologies and effectively reduced the costs and days to drill wells in North Dakota in
an infill development drilling campaign without sacrificing quality standards.
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List of Tables
Table 1 - Snapshot of drilling process documentation used for WTCRW................................................. 17
Table 2 - Example of daily drilling report generated in old reporting software. ..................................... 25
Table 3 - Example of daily drilling report generated in the new software. ............................................. 25
Table 4 - WTCRW lean analysis worksheet. .............................................................................................. 30
Table 5 - Count of NPT events associated washpipe packing leaks.......................................................... 48
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List of Figures
Fig. 1 - Toyota production system “House”. ................................................................................................ 7
Fig. 2 - Well early life cycle. .......................................................................................................................... 8
Fig. 3 - Well inventory for operator in the Williston Basin. ........................................................................ 9
Fig. 4 - Wellbore diagrams of Bakken/Three Forks wells; standard casing design - left; enhanced casing
design - right ............................................................................................................................................... 13
Fig. 5 - Type log showing the Bakken and Three Forks formations. ......................................................... 14
Fig. 6 - Visual representation of the SMED. ............................................................................................... 16
Fig. 7- Weight-to-weight connection with reaming and survey issues. ................................................... 20
Fig. 8 - Example of a weight-to-weight connection with reaming and no survey issues. ........................ 21
Fig. 9 - Example of a weight-to-weight connection in 2016...................................................................... 22
Fig. 10 - Average production hole weight-to-weight connection times by year. ..................................... 24
Fig. 11 - Average spud to release days by month. .................................................................................... 26
Fig. 12 - Spud to release Box and Whiskers plot. ...................................................................................... 28
Fig. 13 - Cellular groupings of drilling sub-assemblies. ............................................................................. 29
Fig. 14 - Pre-spud phase comparison ......................................................................................................... 32
Fig. 15 - 7 types of waste ............................................................................................................................ 33
Fig. 16 - Ishikawa diagram for slow ROP ................................................................................................... 38
Fig. 17 - Sum of downtime, top; count of downtime events, bottom ...................................................... 39
Fig. 18 - Sum of directional drilling downtime, top; count of directional drilling downtime events,
bottom ........................................................................................................................................................ 41
Fig. 19 - Motor and MWD failures by hole section. .................................................................................. 43
Fig. 20 - Sum of rig related downtime, top; count of rig related downtime events, bottom. ................. 44
Fig. 21 - Top drive specific NPT time, top; top drive specific NPT events count, bottom. ....................... 45
Fig. 22 - TDS -11SA Lubrication and Maintenance Guide .......................................................................... 47
Fig. 23 - Unorganized tool storage container ............................................................................................ 50
Fig. 24 - Unorganized wrench tool station. ............................................................................................... 50
Fig. 25 – Driller’s control dashboard displaying casing release override. ................................................ 51
Fig. 26 – Accumulator hydraulic hoses. ..................................................................................................... 52
Fig. 27 - Drilling days on location. .............................................................................................................. 53
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Table of Contents
1. Introduction .......................................................................................................................................... 1
1.1. Scope of Thesis ............................................................................................................................. 1
2. Literature Review ................................................................................................................................. 2
3. Lean Manufacturing ............................................................................................................................. 5
3.1. Background of Lean ...................................................................................................................... 5
3.2. Lean in the Oil & Gas Industry ..................................................................................................... 7
4. Application of Lean to Achieve Drilling Process Improvements ....................................................... 11
4.1. Drilling Operations in the Williston Basin ................................................................................. 11
4.2. Defining a Quality Product ......................................................................................................... 15
4.3. Lean Through Collaboration ....................................................................................................... 15
4.3.1. Well Time and Cost Reduction Workshop I: SMED ........................................................... 16
4.3.1.1. SMED Evaluation of Workshop Data ......................................................................... 17
4.3.1.2. Changing for the Better .............................................................................................. 19
4.3.1.3. Tracking Efficiency Improvements ............................................................................. 22
4.3.1.4. The Importance of Data Quality ................................................................................ 24
4.3.1.5. Results From Workshop I ........................................................................................... 26
4.3.1.6. Lessons Learned from WTCRW I ................................................................................ 27
4.3.2. Well Time and Cost Reduction Workshop II - New Push for Lean .................................... 27
4.3.2.1. Factory Drilling ........................................................................................................... 27
4.3.2.2. Process Variability ...................................................................................................... 27
4.3.2.3. Lean Evaluation of Workshop Data ........................................................................... 29
4.3.2.4. Elimination of Drilling Waste ..................................................................................... 33
4.3.2.5. Non-Productive Time and Root Cause Analysis ........................................................ 37
4.3.2.6. Total Productive Maintenance ................................................................................... 48
4.3.2.7. 5S ................................................................................................................................. 49
4.3.2.8. Mistake Proofing (Poka Yoke) .................................................................................... 51
4.3.2.9. Results from WTCRW II .............................................................................................. 52
4.3.2.10. Lessons Learned from Workshop II ............................................................................ 53
5. Conclusion .......................................................................................................................................... 54
6. Bibliography ........................................................................................................................................ 56
List of Acronyms ......................................................................................................................................... 58
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1. Introduction
Reducing drilling days through efficiency improvements is an effective method for achieving well cost
savings in a standard Rig Operating Rate scenario with spread rates in the $90,000/day range. On
average, the time to drill an onshore well is comprised of 35-50% on-bottom drilling time, with the rest
of the time being consumed by flat time operations. Flat time operations are any activities that do not
result in the hole being deepened but are required to drill the well, and should not be confused with
undesirable Non-Productive Time (NPT). This implies that over half of the overall drilling time is taken
up by non-drilling activities. Within the drilling process are embedded inefficiencies, that when
eliminated will reduce the amount of time required to deliver wells to the next internal customer of the
overall well construction process.
A tremendous amount of focus in the industry has been devoted to improving penetration rates with
little attention to flat time operations that book-end any on-bottom drilling time. As on-bottom drilling
time is reduced through technological advances and improved drilling practices, the total percentage of
flat time operations becomes a larger component of the overall time to drill a well. Improving flat time
operations should be as high of a priority as on-bottom drilling.
One approach to improving the drilling process is through implementation of Lean concepts. Lean
essentially is a critical review of a process with the goal of recognizing and eliminating non-value adding
activities known as “Waste”, while maximizing value to the customer. In this situation, drilling is the
process under review, with the well as the manufactured product and the completions group as the
customer. The steps to drill a well in a development infill scenario should be, for the most part, fully
repeatable and readily optimized similar to assembly line production in a factory. Though this should be
the case, variability runs rampant in most drilling campaigns. It is not uncommon for two rigs with
identical configurations, drilling in similar geologies, and following the same procedure, to drill their
wells in different manners and in varying amounts of time.
The first step towards efficiency optimization should be the elimination of variability, ensuring that all
rigs perform the drilling process the same. Once this is achieved, a reduction in standard deviation and
average drilling days will be realized. The following and forever ongoing steps should then be striving for
process optimization through the quest and elimination of embedded process waste. Perfection is
never fully achieved but should always remain as the ultimate goal.
1.1. Scope of Thesis
Lean has been used across a wide array of industries to improve product delivery both from an
efficiency and cost perspective. This thesis reviews the applicability of Lean to the oil and gas industry,
in particular the drilling process of the overall well construction process. The paper is written in third
person but is an account of my experiences working for an operator, whose identity will be kept private,
and our journey with Lean and the pursuit of drilling process perfection.
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2. Literature Review
Lean Drilling – Introducing the Application of Automotive Lean Manufacturing Techniques to Well
Construction (de Wardt 1994)
Lean methodologies developed in the automotive industry can be applied to drilling operations to
successfully improve efficiency and cost. Lean production combines the advantages of craft production
and mass production while avoiding the high cost of the former and rigidity of the latter. Because of the
highly customized design in many well construction processes, drilling is most analogous to craft
production. In some areas of operations, a large scale of repetition of similar wells has allowed for
standardization and mass production to be achieved after enduring a typical learning curve in the early
phases of developing a new area.
Developing a close relationship with suppliers, to the level of partnerships or alliances, is essential to the
implementation of Lean. Relying on a supplier’s knowledge and skill set permits a reduction in time
through the offline assembly of products required for the primary process, and the efficient use of
specialized tools. This reliance removes some of the detailed engineering, design and execution
management from the owner/operator of the well. Suppliers are viewed as integral to the entire
production process and incorporated into all phases of the product from design, execution and lastly to
evaluation.
Similar to the automotive industry in the incorporation of technology, directional drilling and the drilling
of horizontal wells has allowed for production increases at lower cost per barrel. Further improvements
must come through organizational improvements through Lean production methods. What the
automotive industry incorporated was breaking the entire process into sub assembly components which
constitute logical and efficiently combined elements of the final product. Lean production has evolved
the relationships of each manufacturer of a process to achieve significantly increased efficiency and
quality in the overall process.
Implementing Lean Manufacturing Principles in New Well Construction (Charles, Deutman, and Gold
2012)
Aera Energy LLC based out of California is in an intensive drilling program manufacturing 1000+
producers and water/steam injectors per year. Due to the high level of activity involving around 800
contractors, logistics can be quite complex and rife with inefficiencies. Realizing the need to improve
their operational efficiency, Aera set out on an improvement journey starting in 2001 surveying multiple
industries for the most effective way of achieving their desired improvements. The management team
settled on Lean principles to meet their goals.
Some of the problems that Aera identified were large, hard to manage projects, very long-lead planning
times prior to spud and difficulty implementing the major steps in the process – building facilities,
drilling, well completion and well hook-up. This lead to major congestion issues in the field.
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Aera created a Development Team to make use of continuous flow process to level load the work and
eliminate waste. The Development Team is broken into two sub-groups, the Design Team and the
Implementation Team, who have specific responsibilities working through “gates” with well-defined
deliverables. The Development Team integrated the various functions required for the Well
Construction Process, i.e. reservoir, geology, drilling, and operations. Aera found that reducing the
waste in processes, continuous improvements, using a pull system, level loading production, mapping
the value stream, finding and fixing problems and transparency through visual controls were the Lean
tools most applicable to their improvement efforts.
Part of the Lean transition required a cultural change and also a modification of the conventional
manufacturing concept that instead of the product moving past stationary workers, the workers moved
past a stationary product. There was also the need to establish alliances with suppliers that could be
trusted and would take part in the continuous improvement efforts on their own.
For the project to be successful, Aera recognized that leadership commitment, discipline and
persistence, trust between Aera and their suppliers and excellent information management and
technology were paramount.
Application of Lean Six Sigma in Oilfield Operations (Buell and Turnipseed 2003)
Lean Six Sigma and International Standardization Organization (ISO) systems can be used in conjunction
with each to create sustainable, continuous improvement in upstream operations. Lean Six Sigma is
marriage of Six Sigma, a process-improvement methodology that focuses on delivering products at a
lower cost, with improved quality and reduced cycle time by reducing process variation, and Lean, a
process-improvement methodology that focuses on removing non-value-added activity and aligning
production with customer requirements. Historically Lean advocates recognized Six Sigma as a tool that
supported Lean and Six Sigma advocates recognized Lean as a tool for reducing cycle time and
inventories, but the two approaches were also viewed as competing with each other. Only within the
last few years were the two methods merged into a single process-improvement methodology: Lean Six
Sigma. ISO is used for controlling operating procedures, assessing the capability of quality systems,
sustaining continuous improvement, and managing records and documents.
Six Sigma makes use of mathematical equations to measure variability and are as follows:
Process Capability Potential
Cp = (USL – LSL)/6σ Equation 1
Process Capability
Cpk = minimum of [(USL – xbar)/3σ or (xbar-LSL)/3σ] Equation 2
Sigma Level
σlevel = minimum of [(USL-xbar)/σ or (xbar-LSL)/σ ] Equation 3
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Quality is improved through increasing the σlevel and reducing the number of process steps. Lean Six sigma works both dimensions to accomplish quality improvement. A fusion of Lean Six Sigma and ISO was used for a series of improvement projects in North America and Asia. An example of the projects was improvement to Rod-Pump Repair through reducing the number of pump designs, a reduction in inventory, reducing the number of pump storage locations, new dedicated pump delivery service, more insert pump designs, an audited ISO 9001 quality system to improve the rating of pump repair shops, and optimized settings of the internal pump clearance to maximize pump run life. Overall 11 projects in North American oil fields, resulting in a net benefit of $500,000 per project, and 16 projects in Southeast Asian oil fields, resulting in a net benefit of $1,000,000, were successfully completed.
Application of Lean Principles to Accelerate Project Development (Tønnessen et al. 2015)
In effort to reduce the total amount of development time for smaller fields in offshore Norway, Lean principles were used to “Fast Track” the process from beginning to end. Since the discoveries of major field with complex designs are decreasing, an improved, faster and less expensive approach is required to develop the smaller fields. A team was assembled that used the following to achieve their improvement goals.
Standardization
Collaboration
Streamlined process
Change Management Through their efforts, the total time required to develop a project reduced from 5.3 days down to just over 3 days. Through standardization, the team was able to reduce the number of complex, customized designs that required long lead times to a few designs that could be widely used. A well design was chosen based on a basis of design with standardized design options that were selected on the following constraints
Maximum well pressures, temperatures and depths
Casing programs
Well completion options If a well could not be designed based on the criteria, it did not qualify for Fast Track Through collaboration the team was able to accelerate the long lead time that was normally required for planning. One example is the directional plan development that would require multiple weeks of back and forth emails between the directional planner and the geologist to agree on a design. This was improved through a meeting with the lead engineer, the well planner and the subsurface specialist to agree with a plan in only a few hours.
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The streamlined process improvement made revisions to the way a project was planned such as whether a well met the Fast Track criteria. The initial decision gate 0 would already have established whether a project met the conditions or not. Once a project was selected as Fast Track, then well planning could start instead of waiting for project sanctioning and performing the tasks in sequence. Change Management was required to insure success of the Fast Track process change since this would require adoption of new ways of planning. The team needed to be comprised of individuals that would embrace the change and adapt quickly. The individuals needed to be able to provide the necessary value to the project and engage in regular Fast Track Workshops for planning. Involvement from Management was also required to identify KPIs that would track the success of the project.
3. Lean Manufacturing
Lean is the relentless pursuit of perfection through the elimination of waste. Lean maximizes value to the customer through process and resources optimization. Lean has become regarded as one of the most effective process improvement methods.
3.1. Background of Lean
The Lean principles in place today evolved over the latter half of the twentieth century starting in the
early 1950’s in Japan. Lean manufacturing married the efficiency of mass production with the attention
to detail and quality of craft production. One of the most famous and successful early initiatives for
mass production that contributed the development of Lean, came from Henry Ford when he developed
flow production for automobiles. Flow production made use of a combination of interchangeable parts
and assembly line conveyance passing the production components past stationary workers to quickly
manufacture automobiles (Lean Enterprise Institute 2016a). The process was established to fully
incorporate repetition within stations through standardized work and designed-for-purpose tools and
machinery that could be operated by minimally skilled employees and go/no-go gauges. Ford’s desire
was to manufacture the Model T, his most successful vehicle for the masses in the early 1900’s, at fast
rates and affordable prices through his “flow production” manufacturing process. His automobile
became so popular domestically in the US that he opened a manufacturing plant in the UK and made the
Model T available for Europe.
After a while, the public grew bored with the standardized design of the Ford’s vehicles yearning for
variety. Unfortunately for Ford, customization was very difficult, expensive and time consuming to
achieve as the fit for purpose machinery used for manufacturing his automobiles could not easily be
changed over. Customers desiring change could only resort to craft car manufacturers which meant
longer wait times for the specialized production and much higher prices.
In response to the public’s desire for variety, other automobile manufacturers offered customization
such as GM who offered yearly “hang-on features” which could be installed to existing body designs to
sustain customer interest (Womack, Jones, and Roos 1990a). Although, the public was pleased with the
alternatives, the new design changes meant that the other car manufacturing companies lagged in
through put times compared to Ford since extra processing was involved. In effort to become more
efficient, the companies invested heavily in the latest most expensive machines that would increase the
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production rates at specific stations but often led to the buildup of inventories in between stations as
one out-paced the other. These machines also were often difficult to set up and change out parts.
Should an error in the manufactured parts occur, instead of stopping the assembly line to address the
issue, the error would remain throughout the manufacturing process and be fixed on the back end. This
led the need of additional resources to fix problems afterwards and often resulted in a loss in quality.
While the US pioneered and was fully embracing mass production achieving maturation with time, Japan
lagged behind the rest of the automotive industry. Understanding the general public’s desire for variety
but also recognizing that there were considerable inefficiencies in mass manufacturing processes that
already existed, Kiichiro Toyoda, Taiichi Ohno and others at Toyota focused their attention on the entire
automobile manufacturing process instead of the performance of individual machines and their
utilization. The need for optimizing resources was driven by a shortage of resources, both human and
supplies post World War II. Toyota concluded that by right-sizing machines for the actual volume
needed, introducing self-monitoring machines to ensure quality, lining the machines up in process
sequence, pioneering quick setups so each machine could make small volumes of many part numbers,
and having each process step notify the previous step of its current needs for materials, it would be
possible to obtain low cost, high variety, high quality, and very rapid throughput times to respond to
changing customer desires (Lean Enterprise Institute 2016a). This shift became known as the Toyota
Production System (TPS).
The Toyota Production System was based on two main concepts that formed the pillars of the operation
(Fig. 1). The first was built-in quality which came through automation with a human touch, known as
Jidoka in Japanese. Toyota implemented a requirement that should an error in a manufactured part
occur, the entire production line would be stopped and the error resolved before manufacturing could
resume. This philosophy focused on delivering high quality products to the customer with the
customers’ needs as the main driver. The second pillar was Just-In-Time (JIT) manufacturing which is an
inventory management philosophy where parts would only be manufactured on an as needed basis,
eliminating the unnecessary and wasteful build-up of inventory. Downstream partners would pull parts
from upstream partners only when the part was required. In conjunction with the pillars, Ohno
recognized the importance of buy-in from everyone involved in the manufacturing process for
continuous improvement and that without the human component, the operation would be
unsuccessful. Employees needed to feel empowered and have a desire to strive for perfection for
improvements to be achieved. TPS is maintained and improved through iterations of standardized work
and kaizen.
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Fig. 1 - Toyota production system “House” (Lean Enterprise Institute 2016b).
In the book The Machine that Changed the World (Womack, Jones, and Roos 1990b) the author
performs an in depth review of TPS and its success which he refers to as Lean production. The ultimate
goal of Lean, is striving for perfection through the elimination of process waste, known as Muda in
Japanese. Countless companies have since adopted Lean methodologies, spanning virtually all
industries to an extent, to improve their processes, whether manufacturing a product or providing a
service, to enhance efficiency and increase revenue. Examples of Lean in other industries are the
medical field as demonstrated by Virginia Mason Medical Center in Seattle, Washington where they
used lean to improve patient care processes (Miller 2015), the military with the manufacturing of
defense equipment (Cook and John 2001) and World Wide Postal Services reducing processing costs
while improving on-time deliveries (Miller 2005).
3.2. Lean in the Oil & Gas Industry
Lean improvement methodologies have yet to gain much traction in the Oil & Gas industry and seem to
be lagging behind many other industries. Though this is the case, Lean is beginning to gain in popularity
due to the need to reduce well costs with the current state of heavily depressed oil prices. Operators
that are weathering the proverbial “Storm” the best are looking for ways to do more with less without
sacrificing quality. If quality is neglected on the front end during the well construction process, the
productive life of the well may be cut short or incur costly work overs to fix problems that should never
occurred with proper design. Lean has successfully been used to varying degrees to assist some
operators and service providers to maintain positive economics while other companies are shutting
their doors.
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For operators Lean can be used to improve well delivery through reducing cycle time. Cycle time is the
total amount of time required to deliver a well from planning all the way through first production which
is the holistic view of the well delivery process. The well cycle time has several internal
customers/suppliers. Fig. 1 shows a breakdown of the entire well life cycle from planning within the
Subsurface group to production of the well.
Fig. 2 - Well early life cycle.
Should one function group outpace another, then a costly buildup of inventory can cause a
misalignment in capital expenditures to revenue. One example is an imbalance of drilling delivery to the
completions delivery. Since the drilling process is easily repeatable compared to completions, which
may undergo regular revisions to design since the ultimate productivity of a well can be heavily
influenced by minor design changes in a complex multivariate scenario, efficiency improvements often
cause excessive inventories to compound beyond what the completions group can handle. If this occurs
the only way to correct the imbalance is to either reduce drilling activity by rig reduction, barring a loss
of efficiency, or incorporation of additional frack fleets. Fig. 2 is an example of an operator’s well
inventory that was building between the drilling group and the completions group.
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Fig. 3 - Well inventory for operator in the Williston Basin.
The grey bars represent wells that were drilled but had yet to be released to completions since the rig
was still on the pad batch drilling the remaining wells. The magenta bars are wells that had been
released by drilling with the rig moved off the pad ready for stimulation operations. The buildup of
inventory due to drilling outpacing completions caused the well cycle time to increase beyond
acceptable limits as defined by management. Later on in the year, the operator released several rigs
which allowed for the inventory of wells to be reduced to appropriate levels.
Wells in the state of “Drilling rig still on location” is an example of one of the drawbacks associated with
batch-and-queue manufacturing in a multi-well pad scenario and the prolongation of cycle time. Batch-
and-queue is manufacturing a large batch of a single part to reduce the frequency of changing out
equipment. The cost and efficiency savings associated with drilling multiple wells per pad and reducing
the number of rig moves outweighs the temporary buildup of inventory.
Aera Energy LLC, based out of California, is an example of a company that incorporated Lean to improve
the delivery of their wells. Their operations consist of drilling and completing over 1,000 producers and
steam/water injectors per year. With such an active schedule, Aera often found that logistics could be
quite difficult to coordinate with over 800 service providers involved in their operation. Some of the
problems that Aera identified were large, hard to manage projects, very long-lead planning times prior
to spud and difficulty implementing the major steps in the process – building facilities, drilling, well
completion and well hook-up (Charles, Deutman, and Gold 2012).
10
To improve the well construction process, Aera assembled a development team that consisted of
members from subsurface, drilling and operations. Their goal was to find waste in processes, level load
the operation, perform value stream mapping, move away from batch-and-queue and “push”, which
means to move a product to a customer without a request, to a “pull” system, manufacturing a product
on an as needed basis, and implement continuous improvement. The team also made use of visual tools
to provide transparency to problems that needed addressing address.
Through the incorporation of Lean, Aera was able to make substantial improvements to well delivery.
At the time the article was written, the Lean implementation program was in its tenth year which
highlights the fact that the Lean journey takes time and is not an overnight sensation. As waste from
their process was eliminated over the decade, new opportunities would become visible which has
allowed Aera to maintain a state of continuous improvement. Their efforts have resulted in the
consistent release of 1,000 wells per year while maintaining price stability despite oil price volatility.
The company also achieved a reduction in Total Recordable Injury Rate despite the high count of
contractors.
Another company with operations offshore Norway successfully used Lean to reduce the development
of a new project from 5.2 years down to 3. Through the establishment of a selection process, a field
that met specific conditions could be “Fast Tracked” to reduce the amount of time required for
development. The Fast Track team made use of Value Stream Mapping, starting from discovery to
production, to determine each step and associated lead time of the development process and then
targeted opportunities for improvement that became visible.
Service providers to the Oil and Gas industry have also made use of Lean to improve delivery of services
and products. Tools and equipment used for the well construction process fall closer in line with the
typical model of a product manufacturing factory from which Lean evolved. A customer, in this case an
operator, places an order for a product, such as a drill bit, which goes through the manufacturing
process starting from raw material, passed along from station to station as it is assembled until a final
product emerges.
Since operators often make same day requests for a product, service providers must maintain an
appropriate inventory of products to prevent costly delays to the well construction process. Proper
planning and projections of customer demand are essential to balance out the production of new tools
without building of unnecessary inventories.
Sakhardande (2011) surveyed multiple oil and gas equipment producers and service providers and found
the following Lean tools most widely applicable to process improvements.
Kanban – A pull system to manufacture parts only on an as needed basis
5S – Used for organization and neatness within work stations or factories
Poka – Yoke – Mistake proofing or building checks into a process to reduce mistakes
TPM (Total Productive Maintenance) – A maintenance program used to keep equipment in top
condition
Kaizen – Continuous improvement
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Cellular Manufacturing – Arranging stations in logical order for streamlined production
SMED (Single-Minute Exchange of Dies) – Used for quickly setting up or changing out equipment
Value Stream Mapping – A map used to identify the steps and associated time of a process and
embedded waste
Leveled Production – A method for leveling the production of an order over a period by evenly
distributing the daily production volume across the total number of days in the period
Standard Work – A benchmarking tool for tracking employee delivery
Jidoka – Automation of machinery with a human touch
Seven Quality Tools – Graphical tools that are used to troubleshoot issues related to delivery
and quality
Based on the results from Sakhardande survey, 5S, TPM, Kaizen and the 7 Quality Tools were the lean
concepts most widely used in the service industry.
4. Application of Lean to Achieve Drilling Process Improvements
The application of lean concepts to improve drilling operations is not new with one of the earliest
documented cases dating back to 1994, a short 4 years after the release of Womack’s (1990b) first lean
publication. This work was performed by John de Wardt where he used lean techniques to assist British
Petroleum (BP) in the construction and management of wells in their Andrew project (De Wardt &
Company, Inc. 2016). De Wardt developed a tool box of lean concepts that he could apply to drilling and
completion operations which he called Lean DrillingTM. Since 1994, de Wardt has applied Lean DrillingTM
to assist a number of oil and gas companies worldwide in achieving step change improvements followed
by establishing continuous improvement methods that the operators can carry on sustainably without
continuous consultation.
Over the years after the establishment of Lean DrillingTM, other consulting companies have emerged
that specialize in using lean to assist operators in improving drilling operations. The majority of these
companies rely on in-depth knowledge and understanding of oil and gas operations plus lean
improvement concepts to provide a marketable service. Though these companies may be lean experts,
operators can adopt lean concepts independently without any formal training.
In 2013, an oil & gas producer with operations in North America set out on a campaign to improve their
drilling efficiency through the use of lean concepts. Their goal was to reduce the amount of time and
cost to drill their wells without sacrificing quality. The remainder of this thesis focuses on one of the
operator’s drilling team’s journey applying lean, to achieve improvements without the assistance of a
consulting company.
4.1. Drilling Operations in the Williston Basin
The company’s operations discussed in this thesis are in the Williston Basin, located in North Dakota,
and consists of drilling and completing horizontal wells targeting the Bakken and the Three Forks
formations. Well True Vertical Depths (TVD) range from 10,100’ to as deep as 11,300’ with Measured
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Depths (MD) in the +/-20,000’ range. Well designs consist of 9-5/8” surface casing with shoe depths at
+/- 2,000’, a 7” intermediate casing string installed from surface to the landing point of the curve and a
production liner installed from target depth of the well to 150’ above the Kick Off Point (KOP) of the
curve, hung off in the intermediate casing.
The drilling process starts with a turnkey contracted small capacity, truck mounted rig, often referred to
as the “spudder rig”, which drills the surface hole and installs the surface casing offline, prior to the
primary rig moving onto the well. Since the contract is on a turnkey rate, if any problems are
encountered while drilling the surface hole causing operational delays, the operator is sheltered from a
price escalation associated with a typical day rate contract. This is an example of lean relying on an
external supplier to provide a quality, pre-drilled surface hole off the critical path. Once the surface hole
is complete, the spudder rig moves off the pad and the primary rig is then mobilized to the well and
resumes drilling operations starting with the intermediate hole which extends from the surface shoe to
the landing point of the curve. After the intermediate section had been drilled and cased off, the
production hole is drilled horizontally to the Target Depth (TD) of the well after which a liner is installed
with the hanger assembly set in the intermediate casing.
In North Dakota, it is common practice to drill multiple wells per pad together as a batch. This allows for
a reduction in rig moves, which are costly in both time and money, to only one mobilization/de-
mobilization per pad. The move costs can then be evenly split between all wells. In addition, drilling
multiple wells per pad reduces the civil costs on a per well basis. The costs associated with constructing
the pad can be evenly distributed to all wells instead of charged solely against one as is the case in a
single well scenario.
Batch drilling starts with the intermediate sections drilled in sequential order until the last intermediate
hole is drilled and cased off, at which point the rig continues drilling the production hole on that well.
Before the production hole can be drilled though, the 5” drill string used for the 8-3/4” hole section
must be laid down and the 4” drill string picked up for the 6” production hole. In addition, the synthetic
based mud used to drill the intermediate hole must be pumped out of the tanks, which are then cleaned
and filled with brine, the drilling fluid used for the lateral. Once completed, the remaining wells’
production sections are drilled in reverse order. Although lean preaches that batch-and-queue is less
efficient than “continuous flow”, the time and cost associated with swapping out drill strings and drilling
fluids tips the scale in favor of batch drilling. Well inventories undergoing batch drilling are kept low
with the typical count limited to four. The internal customer, the completions group, also conducts their
operations in batches fracking alternating stages across all wells in sequence, known as a Zipper Frac.
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Fig. 4 - Wellbore diagrams of Bakken/Three Forks wells; standard casing design - left; enhanced casing design - right
The casing programs in the Williston Basin vary slightly based on location in the field due to geological
differences. The design shown in Fig. 4 on the left is used throughout the majority of the field. The
enhanced casing design on the right in Fig. 4 is used in an area where the salts are thicker and more
ductile. Heavier casing with higher collapse resistance is required to counteract the loads exerted by the
squeezing salts. Since the heavier casing has a reduced inner diameter, the production hole must be
drilled with a 5-7/8” bit instead of the standard 6” used in the rest of the field. The differences in design
have negligible impacts on drilling performance.
Operators in the Williston Basin target the middle dolomitic portion of the Bakken formation, which is
sandwiched between upper and lower Bakken shale members, and the Three Forks, a primarily
dolomitic formation mixed with mudstone and bituminous shale (Amicone 2014), is located just below
the Lower Bakken Shale, Fig 5. In contrast to the Three Forks, the Bakken production laterals are easy to
drill with one BHA in less than 100 hours. The Three Forks, on the other hand, is much tougher on
downhole equipment. Bits have a tendency to core out often requiring replacement trips to reach TD.
Embedded within the Three Forks are hard stringers that can cause sudden BHA deflections that, if
uncontrolled in the upwards direction, can result in a Lower Bakken shale strike. Once the shale has
been exposed, the well must be sidetracked due to wellbore instability and the risk of the BHA becoming
stuck. The Three Forks is usually drilled in 125 to 150 hours barring any major setbacks.
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Fig. 5 - Type log showing the Bakken and Three Forks formations.
To preserve bit life in the abrasive Three Forks, the mud motor speeds are reduced compared to the
standard Bakken Bottom Hole Assembly (BHA). Bits are also designed to be less aggressive with
increased cutter densities, higher back rake angles and the addition of back-up cutters.
Besides the difference in casing weights, production hole sizes and the drillability of the Bakken vs the
Three Forks, the process for drilling wells in the Williston Basin can be standardized. In general, the
need for customized designs is rare if ever required in a standard operating year. Occasionally a
geological anomaly or downhole equipment failure will require deviation from the standard drilling
process or casing design.
When operators first started drilling horizontal Bakken and Three Forks wells, casing designs and drilling
processes varied significantly usually customized based on uncertainties that exist when learning to drill
in a new area. Because of the frequently changing designs, the well manufacturing process closely
resembled craft production while going through the initial learning curve phase. At this stage in
development, drilling operations in North Dakota more closely resemble mass manufacturing due to the
repeatability in the process and standard well design. Process optimization is now the remaining goal
which can be facilitated through lean implementation.
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4.2. Defining a Quality Product
The drilling process is one component of the overall well construction process which has the goal of
delivering oil and gas to an external customer at the lowest cost possible. The drilling team is an internal
supplier of a drilled and cased off wellbore to the completions group who have the responsibility of
stimulating the well to enable flow of oil and gas in tight reservoirs. The drilling team must consistently
deliver quality wells, on time, with the internal customer’s needs met. To the operator, the value of a
well is defined through the following criteria.
General Criteria
Successfully drill well to permitted target depth remaining within the Authorization for Expenditure (AFE) budgeted amount.
Drill lateral 100% within the target window as defined by geology to maximize reservoir contact.
Provide wellbore isolation from ground water
Withstand future pressure loads associated with completions and production operations
Serve as a conduit for produced fluids and as protective housing for the installation of tubing
and associated artificial lift equipment
Bakken/Three Forks Specific Design Criteria
Dogleg severities limited to less than 1° per 100’ in the vertical portion of the well to reduce
sidewall loading which can cause
o severe intermediate casing wall wear while drilling the lateral resulting in a de-rating of
the burst capacity,
o the mandatory installation of a tie-back if the de-rated burst capacity of the
intermediate casing does not provide enough safety factor for stimulation pressures,
o increased tubing/rod wear once well is on rod lift
The completions group must be able to open sleeves installed at the toe of the production liner
to permit the pumping down of the first set of wireline conveyed perforating guns
If the drilling group manufactures a well with any of the design criteria not met, well economics are
usually impacted either through impaired production or costly work overs troubleshooting problems. It
is critical that constant communication between the supplier, the drilling group, and the immediate
internal customer, the completions group, and the further down the line internal customer, the
production group, is maintained to identify problems that may require modification of the design or
process to prevent the issues from reoccurring.
4.3. Lean Through Collaboration
In 2013, the operator held a collaborative workshop, which they called a Well Time and Cost Reduction
Workshop (WTRCW), where the performed an in depth review of their drilling process. This was their
first exposure to lean in which they applied SMED to evaluate opportunity for improvement. Two years
later the operator reconvened for another WTCRW which built on the first workshop but incorporated
additional lean concepts.
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4.3.1. Well Time and Cost Reduction Workshop I: SMED
The first lean evaluation of the operator’s drilling operations was conducted during a WTCRW held in
July 2013 where the process was mapped and evaluated for improvement opportunities by applying
concepts from SMED. SMED was developed by Shigeo Shingo to improve the change out time of dies
in Toyota’s metal stamping machines. Toyota recognized that one of the main problems with mass
manufacturing’s ability to easily offer variety stemmed from the metal stamping machines which use
upper and lower dies to shape sheet metal into car components, such as fenders. The dies were heavy
as well as difficult and time consuming to change out and could only be performed by specialists. To
reduce the productivity loss associated with the changing out of dies, large batches were manufactured
and change outs were limited.
Through SMED, Toyota was able to quickly change out dies, minimizing downtime, allowing for small
batches and easy incorporation of variety in stamped metal components. The essence of the SMED
system is to convert as many changeover steps as possible to “external” (performed while the
equipment is running), and to simplify and streamline the remaining steps that are “internal”
(performed while the equipment is stopped) (Vorne 2016). The Single-Minute component of SMED
means that the equipment should be changed out in single digit minutes, i.e. less than 10 minutes.
In the workshop a modified version of SMED was adopted where instead of switching out equipment,
each step of the drilling process was evaluated for what could be performed externally and what could
be simplified and streamlined. Moving steps externally were referred to as being performed “in
parallel”. For the simplification and streamline part of SMED, steps were evaluated for what could be
shortened or eliminated. Fig. 6 is a visual representation of the SMED improvement process. As can be
seen, if properly applied, the time and steps associated with a process can be dramatically reduced.
Fig. 6 - Visual representation of the SMED.
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4.3.1.1. SMED Evaluation of Workshop Data
In the workshop, each step of the drilling process was documented in sequential order and evaluated for
what could be shortened, performed in parallel (externally) or eliminated altogether. For reference, an
associated average and best demonstrated performance (BDP) time was also listed for the steps. The
BDP time served merely as a benchmark but not as the ultimate limit for opportunity since the SMED
process rendered some of the operations and their associated times obsolete.
While collecting data for the workshop, it was recognized that the daily drilling reports used for the
analysis were inundated in inconsistencies and errors voiding countless data points for inclusion in the
evaluation. This highlighted a severe need for improvements to the data quality captured in the daily
reports. Operations can’t be managed if they are correctly measured.
In the workshop, participants were encouraged to suggest any ideas that came to mind regardless of
how far-reaching they may seem. The SMED evaluation revealed obvious waste on several occasions
and a few times led to the question of “How was this overlooked?” In contrast to the easily recognized
opportunities, several other steps in the drilling process went through prolonged debates whether
proposed changes would truly provide value or would impose unnecessary safety risks. One example
was the picking up of 4” drill pipe and making up stands in the mouse hole while drilling the
intermediate section eliminating having to perform the steps after running the casing. After much
discussion, it was determined that due to the increased safety risk associated with the simultaneous
operations of handling the drill pipe and drilling ahead, it would not be added to the improvement list.
Table 1 - Snapshot of drilling process documentation used for WTCRW
Phase Drilling Process Well Depth, ft BDP Time,
hrs
Average
Time, hrs
Challenge Elements - Ideas
9900 79.5 120.5
Drill and survey 8-3/4" Intermediate hole to KOP 9900 72 110 Develop consistent, optimized drilling parameters (and contingency
parameters) particularly in the salt
Evaluate bit design to reduce number of bit runs
Decision tree regarding bit trip requirements
Evaluate use of rotary steerable system
Investigate use of a stabilized 1.1 deg motor assembly
Circulate hole clean and pump fresh fresh water pill/Pump
slug/TOOH with to P/U curve assembly
9900 6.5 9.5 Evaluate stabilized assembly
Eliminate fresh water circ.
L/D Vertical BHA 9900 1 1
10750 35.5 57.5
P/U and M/U 8-3/4" Curve PDC and adj bend 10750 8 10 Drill the curve with casing
Drill and survey curve to landing point 10750 16 30 Tom's study to revise the BHA
Circ B/U and conduct short trip to KOP 10750 3.5 6.5 Put shouldered connections on 7" and add CRT to be able to wash
casing to bottom.
Evaluate use of auto-fill float equip.
Circ B/U until hole is clean and trip out L/D DP and BHA 10750 8 11
10750 37.5 50.5
Pull wear bushing/Hold Safety meeting with Casing crew/Rig up 10750 1.5 3
M/U shoe track/P/U 7" 32# P-110 LTC casing to the end of curve 10750 10 14 Buck up shoe and collar off location
Ciculate and condition hole while preparing to cement casing 10750 1 3
PJSM w/ cementing crew/rig up cementing equipment/Pump
spacer/cement slurry/displace fluid until plug is bumped/Check
10750 6 6
Verify casing is landed and back out landing joint and L/D/cleaning
mud tanks and filling w/ brine
10750 2.5 4
P/U and M/U lateral BHA 1.5 bend MM/Stab/MWD/Stab/Monel 10750 1.5 2
Trip in hole P/U 4" DP 10750 12.5 16 PU and stand back of the 4" DP (3-4,000').
Pre-strap 4" DP before running 7"
Evaluate move 90' mousehole to be able to torque up pipe
Pressure test csg/Tag Cement and drill out shoe track and 10' of
formation
10750 2 2 Bump plug and test casing
Perform F.I.T 10760 0.5 0.5
Intermediate Casing
Intermediate Vertical
Intermediate Curve
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Process Steps Eliminated - Some of the process steps that were determined to be non-value adding
were eliminated and resulted in significant efficiency improvements associate with the time savings.
Some examples identified in the workshop are the following.
Circulating freshwater after reaching the landing point of the curve to washout salts to prevent
BHA hang up through Charles Salt
o Pumping freshwater would washout the salts to a point that caused problems with hole
enlargement and cement integrity
Short trip lateral assembly at TD
o Deemed not necessary since casing could be ran without encountering any issues
hanging up
Reaming after drilling down each stand
o Reaming caused wasteful processing of the wellbore since the circulating flow rates
were high enough and the mud properties properly balanced to adequately remove
cuttings.
Process Steps Performed in Parallel/Offline - Some of the process steps were found could be performed
offline simultaneously to an operation on the critical path. Some examples are the following.
Pre-drilling surfaces hole with a turnkey contracted spudder rig
o Drilling the surface hole with the primary rig on a day rate contract could result in cost
escalations if a problem is encountered causing operational delays
Strapping, calipering and making up of BHA components offline. Some of the BHA components
came pre-assembled prior to delivery to the rig
o Waiting until it was time to pick up the BHA to strap and caliper the components wasted
time and could easily be performed offline.
Displacing the mud from a water based to an oil based system during drilling out of the shoe
track
o Prior to the improvement, the rig would wait until the hole was fully displaced before
drilling out the shoe track
Buck up casing float equipment at the shop before being shipped to the rig
o Making up float equipment is easily handled with a bucking machine in the shop and
eliminates the time associated with bucking it up at the rig.
Process Steps Shortened - Some of the operations were found could be improved through
standardization. Some examples are as follows. Standardized salt drilling procedure
o Each drill site supervisor had their own method for drilling a 1000’ thick salt section that
would cause the BHA to become stuck if drilled too aggressively. After reviewing the
electronically recorded drilling data of several rigs, the rig that drilled the salts the most
efficiently was recognized and their method became the standard.
Standardized nippling up Blow Out Preventers (BOPs) and testing procedure
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o The process for nippling up the BOPs varied from rig to rig with some less efficient than
others. A BOP task force was assembled and standardized the way the BOPs would be
nippled up and tested
Standardize Weight-to-Weight connections
o Standardizing the weight-to-weight connection process was recognized as a significant
efficiency improvement opportunity due to the high count of connections performed
during the drilling of a well.
4.3.1.2. Changing for the Better
The incorporation of improvement findings had mixed results with some proving out to be immediately
achievable and successful, some not being feasible and others delayed because of being met with
resistance from field personnel since it required a mindset change to “we’ve always done it that way.”
This highlighted the necessity for a cultural change and establishing buy-in from all levels involved in the
lean initiatives. It quickly became apparent, that without buy-in from the field personnel, from the drill
site supervisor down to the rig crews, improvement changes would not be successful.
Some of the changes found to be controversial were at one point necessary during the early
exploratory/appraisal stages of drilling horizontal wells in the Bakken and Three Forks formations. The
extra precautionary steps being challenged improved success rates of well delivery. Later on, once the
development/infill drilling stage was reached and the drilling process had matured, many of extra
measures for ensuring well delivery were no longer valid. Abandoning old practices caused a great deal
of discomfort for the drill site supervisors that feared change.
One of the most debated changes became eliminating reaming after drilling down of each stand.
Several of the drill site supervisors had at one point in their careers experienced stuck pipe associated
with inadequate hole cleaning. Their negative experiences usually dated back to the days when rigs
were power limited and sufficient flow rates for proper cuttings removal could be problematic. Reaming
after each stand resulted in considerable amounts of time lost over-processing the wellbore when
multiplied times the number of connections required for drilling a well.
Fig. 7 shows a typical weight-to-weight connection prior to the workshop. A weight-to-weight
connection is the total amount of time spent making up the next stand of drill pipe starting when the bit
is picked up off bottom lasting until it is back on bottom drilling. During the connection, time is lost to
reaming the wellbore, pumping up of the Measurement While Drilling (MWD) survey, determination of
the next slide orientation and length based on the calculated wellbore trajectory, and then orienting the
bit tool face for sliding in the desired direction.
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Fig. 7- Weight-to-weight connection with reaming and survey issues.
The following are the detailed components of the connection shown in Fig. 7.
Weight-to-Slip
Component 1: The hole is reamed up and down twice after drilling the stand down at the start of the
connection. (Total duration 4.52 min)
Component 2: A turbine powered MWD is activated and records the inclination and azimuth orientation
of the survey tool located 72’ from the bit, followed by circulating up of the survey which conveys the
results of the survey through mud pulses. Results from the survey are used to calculate whether a
trajectory correction slide is required. If a slide is required, a toolface orientation and slide length are
calculated based on the yield of the bent housing motor. If the proper flowrate sequence is not
followed to activate the turbine and MWD, the process has to be repeated, which is the case in the
example above. (Total duration 12.53 min)
Slip-to-Slip
Component 3: The drill pipe is set in the slips to make up the next stand for drilling the next 90’. (Total
duration 2.97 min)
Slip-to-Weight
Component 4: The drill pipe is lifted out of the slips and, as was determined from the results of the
MWD survey, the tool face is oriented for a directional slide before the bit is set back on bottom. (Total
duration 5.08 min)
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The connection in Fig. 7 is inundated with process waste. An immediate reduction in time of 4.5
minutes is achievable through eliminating component 1, reaming at the start of the connection. Fig. 8 is
an example of a connection from the same well where the MWD survey was successfully transmitted to
surface on the first attempt only requiring 4.96 minutes to complete. Based on this information, there is
7.57 minutes of waste associated with reshooting the survey in the first connection. This highlighted the
need for the directional company to standardize their surveying method, one of the action items from
the WTCRW.
Fig. 8 - Example of a weight-to-weight connection with reaming and no survey issues.
A few of the rigs in the fleet immediately made adjustments to their weight-to-weight connection
process resulting in the elimination of waste. For the other rigs that chose not to abandon their old
practices, they soon were being outperformed receiving negative attention from management.
Since the WTCRW in 2013 and the initial recognition for the need to improve weight-to-weight
connections, continuous improvement has resulted in a dramatic reduction in connection time. Fig. 9 is
an example of a typical connection from 2016. When comparing the problem free connection from
2013 (Fig. 8) to the connection shown below, a savings of 10.22 minutes has been accomplished. In a
standard 10,000’ Bakken/Three Forks lateral with 110 connections, a 10.22 minute savings reduces the
overall time for connections by 18.74 hours.
Some of the additional changes to the weight-to-weight connections that have permitted the
continuous improvement are the following:
Flow off MWDs that are powered by battery. Eliminated the need to activate the turbine
powered MWD through a flow sequence. Surveys can be taken during the slip-to-slip segment.
22
Directional drillers are required to remain on the rig floor at all times and be ready to calculate
slide lengths and tool face orientation immediately. In 2013, directional drillers would often
remain in their trailers and only walk up to the rig floor once the surveys had been successfully
circulated to surface causing unnecessary delays.
Drillers were coached to use a stationary object on the opposite side of the rig floor as a visual
reference to align the drill pipe tool joints at the proper height for setting in the slips. If the tool
joint was too high or low, the iron roughneck could not be properly engaged to make up or
break out the connection.
The placement of items used for connections and the positioning of the rig crews were adjusted
to improve flow of movement for stabbing the next stand of drill pipe and threading it to the
drill string in the hole.
Fig. 9 - Example of a weight-to-weight connection in 2016
4.3.1.3. Tracking Efficiency Improvements
The measuring and tracking of performance improvements became an essential component to
facilitating the workshop changes and visualizing the impact. Through the establishment of Key
Performance Indicators (KPIs) rig crews could benchmark their level of performance. Before the
establishment of the KPIs, the rig personnel operated in a state of unknown. They had no reference
points to which they could compare their performance. As an analogy, it is similar to playing a sport
without a scoreboard or tracking statistics. Everyone is left guessing as to how well they are performing
but assumptions are usually made that each respective team is the best.
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In the early phase of rolling out the changes, a wide spread in performance developed as the rigs that
were open to change quickly showed the impact on performance the improvement findings made
possible, where those that resisted the changes had performance levels remain flat. Instead of taking
the stance that we’ll simply replace any reluctant personnel, the operator treated the personnel as
irreplaceable valuable resources and chose to work with them in educating the importance of what was
being requested. The operator used the KPIs to show the rigs where they stood in the rankings and
what was achievable. This was where the alpha mentality, which so often exists in the oil field, assisted
in achieving buy-in, as the rigs now had performance scoreboards and did not want to be the weakest
performers. Once this breakthrough was achieved, the gaps in performance narrowed and the overall
average for drilling days reduced.
The data used to create the KPIs came from two independent sources. The first source was the daily
drilling activity reporting software database, which was used to perform the SMED analysis. The
recording and tracking of operations through the reporting software requires manual selection of
activity codes and hand typing descriptions of the operations and associated start and stop times.
Because of the human error, data quality can be an issue. Operations are frequently miscoded and the
hand typed descriptions sparse in detail. Time rounding is done liberally skewing the true duration of an
activity. Attempting to perform a duration analysis on too fine of a level will lead to erroneous results.
One example is the time required to install a wellhead wear bushing. A query of the database results in
30 minutes to perform the task in almost every case. In reality, a wear bushing can be installed in under
10 minutes. The time is rounded up by 20 minutes. This highlights the caution that should be exercised
when performing a KPI analysis on too fine of a scale when the source is the daily reporting database.
The daily drilling reports should only be used for broader KPIs such as spud to release times.
The second data source used for KPI tracking is provided by a third party drilling performance
monitoring company which provides to-the-second levels of detail of drilling operations. The company
makes use of state detection algorithms to breakdown electronically recorded drilling data into their
respective operations which is then stored in a database and accessible for statistical analyses. The
electronically recorded data is fed by sensors located throughout the rig. Because the data is recorded
automatically, human error and rounding error is removed from the measurements. The weight-to-
weight connections discussed earlier are an example of a sensor derived KPI. Fig. 10 shows the average
yearly production hole weight-to-weight connection times for all connections made by the operator’s rig
fleet generated through the performance monitoring company’s service. It can be seen that continuous
improvement has been achieved year over year.
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Fig. 10 - Average production hole weight-to-weight connection times by year.
4.3.1.4. The Importance of Data Quality
On-bottom drilling efficiency is another KPI that can be tracked through the performance monitoring
services with a high level of accuracy but only comprises 35%-45% of the total drilling process time for
an average performing rig. The other 55%-65% consists of flat time operations some of which have
associated sensors, e.g. making connections, tripping pipe, running casing, and the rest which cannot be
recorded through sensors and only can be tracked through observational recording, e.g. nippling up
BOPs, cleaning of mud tanks and rigging up of equipment. Tracking the performance of the latter
operations is limited to the quality of what is logged in the reports.
At the time the WTCRW in 2013 was held, the operator was using a basic reporting software that limited
the classification of operations to a single level. Grouping by hole phase or dividing a main process into
individual components was not an option unless conducted manually on the backend. Table 2 is an
example of the operational breakdown of running casing generated in the reporting software. As can be
seen, “Casing and/or Cementing” is the main grouped process that is being captured which is comprised
of rigging up the casing crew, running the casing, rigging up of the cement crew, cementing the casing
and finally rigging down of the crews. A quick multi-well query to analyze the time for only cementing
operations is not possible. The reporting software also did not allow for the designation of non-
productive time. Only after reading the report below, would it become apparent that there is
embedded NPT during the installation of casing, which are waiting on equipment and services and
changing out failed equipment.
25
Table 2 - Example of daily drilling report generated in old reporting software.
In 2014 the operator made the decision to change the reporting software to a more advanced
alternative. This was done out of recognition that the old software simply was inadequate for proper
analyses of performance.
The new software allowed for four levels of classification of operations which are the following
Activity Phase – Classifies operations based on hole section (surface, intermediate, production)
and by main operational process (moving, rigging up, drilling, casing). Groups certain activities
similar to the old report software such as casing and cementing activities
Activity Code – Classifies the Activity Phase on a finer level, e.g. Casing and Cementing become
their own codes
Activity Sub-Code – Operations are broken down to the finest level that specifies what is
happening within the two higher levels of classification, e.g. “Run Casing” or “Pull Casing”
Activity Classification – Classifies an activity as “productive” or “non-productive”.
Table 3 - Example of daily drilling report generated in the new software.
Date StartTime EndTime Hours IADCDescription Remarks
10/5/2013 6:30:00 PM 8:00:00 PM 1.5 12 - Casing and/or Cementing PJSM rig up casing tools.
10/5/2013 8:00:00 PM 10:00:00 PM 2 21 - Other Wait on torque turn. (lay down DP).
10/5/2013 10:00:00 PM 10:30:00 PM 0.5 12 - Casing and/or Cementing Rig up torque turn.
10/5/2013 10:30:00 PM 6:00:00 AM 7.5 12 - Casing and/or Cementing Run 7" casing.
10/6/2013 6:00:00 AM 10:00:00 AM 4 12 - Casing and/or Cementing Run 7" casing.
10/6/2013 10:00:00 AM 11:00:00 AM 1 12 - Casing and/or Cementing Power tongs failed, change out to back up set, rig torque turn back up.
10/6/2013 11:00:00 AM 2:30:00 PM 3.5 12 - Casing and/or Cementing
Run 7" casing, Run 112 Jt's ( 4,900.96' ) 7" 29# DWC Casing M/U Torque 25K, M/U Rpm 12 High
4 Rpm Low, Shoe 2.3' Set @ 4,918.14' Float Collar 1.635 Set @ 4,823.82', 1 Semi-Ridged
Centralizers Per Joint in Curve & 1 Bow Spring Centralizer Every 3rd Joint F/ KOP T/ 300' From 9
5/8 Shoe.
10/6/2013 2:30:00 PM 11:00:00 PM 8.5 21 - Other Circ. And wait on Cementers.
10/6/2013 11:00:00 PM 2:00:00 AM 3 12 - Casing and/or Cementing
PJSM, rig up cementers, cement 7". 20 bbls invert-flush at 10.0 ppg, 20 bbls invert spacer at 10.0
ppg, 70 bbls brine spacer + 0.2 gal/bbl ACW-4, 305 sks0:1:0 G + additives at 15.8 ppg.179 bbls
fresh water displacement.
10/6/2013 2:00:00 AM 2:30:00 AM 0.5 12 - Casing and/or Cementing Rig down Cementers
DATE_REPORT ACTIVITY_PHASE
ACTIVITY_
CODE
ACTIVITY_
SUBCODE TIME_FROM TIME_TO ACTIVITY_MEMO
ACTIVITY_
CLASS
ACTIVITY_
DURATIO
1/14/2016 21INRC RU 1/14/2016 11:00 1/14/2016 12:00 PJSM and R/U CRT and casing equipment. P 1
1/14/2016 21INRC Casing Run Csg 1/14/2016 12:00 1/14/2016 14:00 PJSM and made up 2 joint shoe track of 9-5/8'', 47 ppf, P-110, BTC Casing with pre bucked on float shoe and float collar to 178'. Circulate float equipment. Had trouble making up shoe joint due to poor alignment. P 2
1/14/2016 21INRC Other 1/14/2016 14:00 1/14/2016 15:00 Level mast PN 1
1/14/2016 21INRC Casing Run Csg 1/14/2016 15:00 1/15/2016 0:00 Run 9-5/8" 47 ppf, P-110, BTC casing from 178' to 7,750'. Filling every 25 joints ran and the average make up torque was 10,000 ft/lbs.P 9
1/15/2016 21INRC Casing Run Csg 1/15/2016 0:00 1/15/2016 2:00 Ran 9-5/8" 47 ppf, P-110, BTC casing from 7,750' to 9,471'. Filling every 25 joints ran and the average make up torque was 10,000 ft/lbs.P 2
1/15/2016 21INRC Casing Run Csg 1/15/2016 2:00 1/15/2016 2:30 P/U Cameron 9-5/8" hanger and running tool. Wash down from 9,471’ and landed hanger with 303 Klbs suspended below hanger with casing shoe at 9,510'. Wash down with 450 GPM, 500 PSI.P 0.5
1/15/2016 21INRC Circ & Cond 1/15/2016 2:30 1/15/2016 3:30
Circulate casing capacity through CRT, 450 GPM, 300 PSI. Held safety meeting with
Halliburton and rig crew to review cement operations. Rigged up Halliburton cement lines,
load cement head with top and bottom plugs and witnessed by DSM. P 1
1/15/2016 21INRC Cement Primary 1/15/2016 3:30 1/15/2016 7:30
Install cement head and pressure test line to 8,000 Psi. Good test.
Mix and pump cement for (Intermediate) casing as follows:
Pumped 30 bbls FW spacer – 8.33 Ppg @ 4.5 bpm and 320 psi. Dropped bottom plug.
Mix and pump lead cement 469 bbls – 13.0 ppg – 7.0 bpm at 585 psi.
Mix and pump tail cement 80 bbls - 16.2 ppg at 6.4 bpm, 609 psi.
Dropped top plug. Pumped 690 bbls of 12.5 ppg SBM displacement at 8.0 bpm, slowing
down to 3 bpm on the last 10 bbls displaced. Final circulating pressure was 600 PSI. Bumped
plug and increased pressure to 1100 PSI.
Bumped plug on calculated displacement of 690 bbls. Held 5 min then pressured to 6,500
psi. Held and charted casing pressure test for 30 mins. Bled back 16 bbls, and verified floats P 4
1/15/2016 21INRC Other 1/15/2016 7:30 1/15/2016 8:30 Flush lines, backed out and laid down landing joint. P 1
1/15/2016 21INRC RD 1/15/2016 8:30 1/15/2016 9:30 PJSM and rigged down CRT and casing equipment. Cleaning tanks and well deck. P 1
26
Analyzing drilling the data became much more comprehensible through multi-leveled classifications.
Efficiency gaps and waste could be honed in on much quicker through simple queries. Similar to the
previous software though, quality was essential and any errors in reporting could cause erroneous
interpretations of results. The engineer should perform the final quality check for what is logged at the
rig on a daily basis.
4.3.1.5. Results From Workshop I
The year following the workshop was spent working with the field personnel educating them over the
reasons for the changes and why their buy-in was crucial for success. Fig. 11 shows the largest scale KPI
used to track operational performance, Spud-to-Release time, which starts the moment the well is
spudded and lasts until the rig is released. In the situation of pre-setting the surface casing, since the
task is performed offline, the spud date and time starts after a successful Formation Integrity Test has
been completed at the start of the intermediate hole section. In the chart below, it can be observed
that immediate time savings were realized in the month after the workshop attributable to temporary
acceptance of “easy win” changes. In the months following August, a loss in efficiency was experienced
which resulted from some rigs abandoning the changes that had so successfully worked. This
highlighted the need to provide the rigs the KPIs on a regular basis to visually show the impact changes
had on performance. The remainder of the year was spent breaking down the resistance barriers
associated with the more controversial changes. It wasn’t until a few months short of a year before
widespread acceptance of the improvement initiatives was achieved.
Fig. 11 - Average spud to release days by month.
27
4.3.1.6. Lessons Learned from WTCRW I
The first workshop proved to be successful but not without challenges. The main lessons learned were
the following.
Buy-in was essential
Buy-in takes time
Data quality was severely lacking and needed to be improved
KPIs needed to be tracked and provided to the rig
Once KPI data was made available to the rigs, performance improved as the rig crews had a
reference benchmark and a desire to be the best
4.3.2. Well Time and Cost Reduction Workshop II - New Push for Lean
In the summer of 2015, two years after the first WTCRW, oil prices had fallen by 50% and the need to
further reduce costs was imperative. By this time, most of the low hanging fruit had been picked and to
achieve further continuous improvements the operator decided to reconvene as a cross functional
group and hold another workshop, this time reaching deeper into the Lean toolbox.
4.3.2.1. Factory Drilling
In the new workshop the operator set their focus on achieving a “Factory Drilling” mode of operating or
in other words, standardizing the delivery of quality wells in the shortest amount of time possible in a
streamlined fashion with zero process variability. The manufacturing process of a well should be fully
repeatable with a standard deviation of zero. The ultimate goal of the factory is to strive for perfection
through continuous improvement.
4.3.2.2. Process Variability
Fig. 12 is a Box and Whiskers plot of drilling Spud-to-Release days dating back to the first year the
operator began in the Williston Basin, broken out by formation. The tightening of the boxes and
shortening of the vertical line lengths portrays a reduction in the average and standard deviation of
drilling days through continuous improvement. The reduction in the standard deviation has been a
result of eliminating process variability. The lowest point of all of the lines expanding below the boxes
represents lost opportunity time and are examples of what is achievable.
28
Fig. 12 - Spud to release Box and Whiskers plot.
Drilling variability can exist in a number of ways preventing a factory operation and can be broken into
three main categories, Process Variability, Equipment Variability and Geologic Variability. Below are
examples of variability in all three categories that are frequently found in a standard drilling campaign.
Process Variability
A rig stops relying on the standardized drilling procedure as they believe they have the plan
committed to memory
A rig decides to drill off the procedure because they believe their way is better
A rig cuts corners to achieve improvements to their drilling statistics usually at the sacrifice of
quality or safety
A rig does not follow a preventative maintenance program and experiences frequent failures
resulting in downtime or diminished capacities
Equipment Variability
Rigs have varying equipment design ratings, e.g. mud pump pressure ratings, draw works power
ratings, etc.
Rigs have different equipment layouts
Rigs have excessive unused equipment or are missing equipment
Geologic Variability
Geological anomalies cause drilling issues, e.g. wellbore instability, lost circulation, excessive
hard stringers causing BHA deflections
Formation markers not correlating with geo-steering comparisons to offset control wells
29
Each example stated above can result in inconsistent drilling durations. Through proper design and
process, the influences of the variables on drilling delivery can be minimized.
When analyzing the standard deviation, an indicator of the degree of variability, the lower end of time
durations should be evaluated for sustainability. If determined that the lower times are repeatable and
sustainable without cutting corners or exposing the crews to increased safety risk, then these can be set
as the performance targets.
4.3.2.3. Lean Evaluation of Workshop Data
Different from the first workshop, focus was shifted from only looking at the overall averages of all of
rigs combined to comparing them on a side by side basis. Performing the analysis by grouping all of the
rigs together hid underperformers. Also instead of evaluating each individual step as a single focal point
in the drilling process, activities were grouped together into logical cells based on common goals, e.g.
the pre-spud phase which is comprised of the sub-assemblies of nippling up the blowout preventers,
making up and tripping in the bottom hole assembly and drilling out the shoe track of the surface casing
as shown in Fig. 13 below in the 20PRES phase.
Fig. 13 - Cellular groupings of drilling sub-assemblies.
Also different from the first workshop, instead of solely relying on SMED to evaluate the drilling process,
other Lean concepts were incorporated into the analysis. Table 4 shows an example of the evaluation
that was performed and the solutions that were discussed to improve efficiency. As can be seen, the
time associated with each sub-assembly varied significantly from rig to rig. The workshop revealed that
20MIRU
•RU Ops
20PRES
•BOP Ops
•Pipe Handling Ops
•Shoe Track Ops
21INDR
•Drilling Ops
•Pipe Handling Ops
21INRC
•Casing Ops
•Cement Ops
•Rig Release Ops
30MIRU
•RU Ops
30PRES
•BOP Ops
•Pipe Handling ops
•Shoe Track Ops
31PRDR
•Drilling Ops
•Pipe Handling Ops
31PRRC
•Casing Ops
•Cement Ops Well
30
not one rig dominated across the board in all areas. The comparison made it possible to recognize
which rig performed the best in a particular sub-assembly which could then be used to observe what
was working so well and replicate the best practices fleet wide.
Table 4 - WTCRW lean analysis worksheet.
The average times associated with each sub-assembly do not include times associated with non-routine
events, or in other words, any activities that are not written into the standard operating procedure.
These events were seen as waste and the total time summed up and listed as “Other”. The purpose of
removing the non-routine events from the standard operations was to level the playing field and
Activity PhaseActivity
Code/Groupings
Subcode/
Sub-
groupings
Non-Routine
EventsRig 1 Rig 2 Rig 3 Rig 4
Fleet
AverageBDP Observations & Notes Action
BOP OPS 11.60 10.60 12.40 8.50 10.78 8.50 a) Standardize start and stop for all phases a) Standardize and document start and stop for all phases
NU/Test/Insta
ll WB 11.60 10.60 12.40 8.50 10.78
8.50
b) Accumulator on B24 attached to subs (obsvtn)
c) For each rig, have configuration comparison to understand
differences
d) Function testing on stump while walking
e) Use data to gauge BOP Testing/NU vendors and use the
best one
f) Consider BOP quick connect flanges ('rapid lock') vs bolts
g) Pull data 'by crew' to see if any trends
h) Are we NU in most efficient order (steps, resources, etc.)
i) Hard line vs flex line to the sub; standardize configuration
j) Tools on hand/nearby and ready to go
k) NU crew all has to be prepped/understand the process
ahead of time; assigned ahead of time
l) Create a PM approach for rams, seals during 180 day
inspection (how many wells then replace; vs wait to fail)
b) n/a
c) For each rig, document configuration comparison to
understand differences
d) Evaluate function testing on stump while walking (document
time savings, risks, costs, etc. - by reconfiguring
accumulators)
e) Analyze data to gauge BOP Testing/NU vendors, follow-up
with DSS; recommend the best one
f) Evaluate use of BOP quick connect flanges ('rapid lock') vs
bolts (availability, reliability, cost/benefit)
g) Pull and summarize data 'by crew' to see if any trends to
idenify if any differences between night and day crews
h) Document and evaluate process flow/diagram for NU
procedure; create and adopt standard procedure
i) Evaluate Hard line vs flex line to the sub; standardize
configuration (flex all the way; or flex to BOP through sub,
etc.) (B13 and 14 thru sub);
j) Conduct 5S evaluation and implementation for Tools to have
them on hand/nearby and ready to go; Have a BOP toolbox/kit
ready to go (5S item)
k) Incorporate standardized tasks for NU in JSA meeting
l) Create a Preventative Maintenance approach for rams, seals
during 180 day inspection (how many wells then replace; vs
wait to fail)
Total Hrs 58.00 58.00 62.50 44.00
m) consider having a set of spare blocks dressed and ready to
go
n) Optimize the swap out procedure to change rams
o) Transport waste of replacement equipment
p) Have a BOP toolbox/kit ready to go (5S item)
q) TPM (total productive maintenance)
m) Evaluate having an extra set of spare blocks dressed and
ready to go
n) Optimize the swap out procedure to change rams
o) Evaluate inventory of spare parts to justify backup set (look
at failure frequency); recommend changes
p) (listed above)
q) Evaluate if TPM (total productive maintenance) is
appropriate system to address downtime, failures
Maint 0% 0% 1% 1%
Other 0% 9% 0% 2%
3-99-36-O
Pipe Handling 6.00 4.73 5.73 4.60 5.26 4.60
MU BHA/Trip
In 4.50 3.40 4.10 3.30 3.83
3.30
a) Standardize BHA m/u procedure
b) Work with directional company to havce standardized BHA
pick-up
c) Share the detailed data for BHA pickup with each rig
d) Preparaton for pickup BHA during testing of BOP
e) Layout of equipment - 5S-mark territory
f) Put the BHA on the catwalk while testing the BOP
g) Prevent 'wrong OD' and connection type incidents
h) Evaluate Non-routine codes per cluster
i) Create Box and Whiskers and Run charts by station
a-g) Standardize BHA m/u procedure (address ideas a-g)
h) Evaluate Non-routine codes per cluster
i) Create Box and Whiskers and Run charts by station
Cut-Slip 1.50 1.33 1.63 1.30 1.44 1.30
Total Hrs 32.00 25.00 28.50 25.50
Maint 3% 2% 2% 6%
Other 13% 14% 4% 4%
Shoe Track OPS 2.35 1.90 2.30 2.80 2.34 1.90
Displace
Mud/Pr Test
Csg/DO
CmtShoe+10'
New
Formation/LO
T/FIT 2.35 1.90 2.30 2.80 2.34
1.90
a) Reuse displaced water
b) Standardize ROP philosphy for Shoe Track
c) Make sure not double testing the casing
d) 5S of tripping in the hole, placment of slips, pipe dope,
layout of equipment
e) Standardize displacement procedure (rate, etc.)
a) Evaluate Reuse of displaced water
b) Evaluate method B14 is using, and Standardize and
communicate drilling parameters for Shoe Track
c) Establish a check in OpenWells to ensure not double
testing the casing
d) 5S Evaluation equipment needed for tripping in the hole,
placment of slips, pipe dope, layout of equipment
e) Standardize displacement procedure (rate, etc.)
Total Hrs 13.25 10.00 13.00 14.75
Maint 4% 5% 0% 3%
Other 8% 0% 12% 2%
Routine Hrs/Well 19.95 17.23 20.43 15.90 18.38 15.00
Non-Routine Hrs/Well 1.00 1.70 0.50 0.45
Rig Eq 4.00 4.00 2.50 1.00
Rig Crew Error 0.00 0.00 0.00 0.00
3rd Party 0.00 3.50 0.00 0.00
Process Gap 0.00 5.00 0.00 1.00
Directional-Tool 1.00 0.00 0.00 0.25
Directional-Error 0.00 0.00 0.00 0.00
20 PRES
31
evaluate how a rig performs under normal operating conditions. The waste evaluation would be
separate component of the workshop.
One of the most compelling differences between the first workshop and the second was achieving buy-
in at the field level. The supervisors and crews had grown accustomed to change over the previous few
years. Achieving buy-in was no longer a barrier to success.
Each phase of the drilling process shown in Fig. 13 is treated as an internal supplier to the subsequent
cell, i.e. each step requires delivery of the well, at progressing stages of assembly. What is left off in Fig.
13 is the surface section as the job of drilling and installing casing is performed off-line by a small fit for
purpose rig, on a turnkey contract. This is an example of an external supplier delivering a quality
product, a cased off surface hole, to a customer, the primary rig, who relies on the expertise of the
supplier. The spudder rig has multiple sub-assemblies, which are essentially sub-sub-assemblies to the
overall drilling process, that are included in the turnkey pricing for drilling the hole, installing and
cementing the casing and installing the wellhead. These sub-assemblies are directional drilling, for
providing a directional nudge in the surface hole, cuttings disposal services for trucking off cuttings to
approved disposal sites, a cement provider who cements the casing and finally installation of a wellhead.
This is an example of interdependencies as discussed by de Wardt (1994).
The surface wellbore must meet the standards required by the following phases of the drilling process
which is the primary rig being able to nipple up BOPs on the wellhead to establish well control and
perform an FIT indicating quality cement. Before that can occur, the rig must rely on a rig mover to
mobilize the rig onto location, assemble the rig with the use of cranes and center the rotary table over
the wellbore the first sub-assembly for the primary rig.
Breaking the drilling process into logical cells, or sub-assemblies, allows for simplified management of
the groups for performance. If too fine of a level is made the data quality becomes an issue. The total
time required to perform the grouped sub-assemblies and number of error occurrences, reveals areas
where improvement is needed. Fig. 14 shows the assembly comparison of the 20PRES or the pre-spud
phase broken into the sub-assembly components of BOP ops, Pipe Handling Ops and Shoe Track Ops.
The amount of variability is evident on an individual rig basis but also on a comparative basis with the
other rigs. The main offender of duration variability for the pre-spud phase are the BOP ops. This
warranted a deeper dive investigation into what the root of the variance was which required direct
observation at the rig site which embodies the Lean philosophy of Gemba (the real place) meaning that
to be able to thoroughly understand an issue, one must leave the office and spend time on the plant
floor or, in the case of the drilling, the well site.
Problems that were observed on the weakest rig recognized in the workshop were the following:
Underutilization of resources – Instead of dividing the rig crew to handle various tasks
associated with nippling up the BOPs and testing, several of the workers remained in a group to
take on individual tasks in sequence. An example that was observed was five guys making up a
32
single hammer union on the choke line. Three of the guys were standing by watching while one
guy held the pipe up and the fifth guy hammered the connection. This is a one person job when
planned properly.
Disorganized equipment and the inability to find the right tools for the job.
Time lost retrieving tools that were stored in a tool box on the other side of the rig
Differences in the way the choke and kill line were routed out of the sub structure
BOP components that wouldn’t test requiring time consuming replacement
Fig. 14 - Pre-spud phase comparison
In the Toyota Production System if an error occurs to the product at a certain phase along the assembly
line, the entire production line would be shut down to fix the problem instead of proceeding and fixing
the problem afterwards. This places accountability on that station of the assembly line to maintain their
equipment by applying a preventative maintenance program. This same philosophy should hold true for
drilling since proceeding with the drilling process with an error usually results in excessive down time
continually applying temporary fixes to failed components. In certain cases, proceeding with a problem
can be life threatening such as in the case of an unsuccessful BOP test. This is an error that without
exception must be fixed before continuing with the drilling process.
Rigs that are perpetual underperformers typically have either a weak crew or bad equipment to blame.
In the situations where the equipment is underrated for the job, an upgrade is warranted. Bad crews on
the other hand will typically blame the equipment but all too often the failing equipment is a result of a
crew not following an adequate preventative maintenance program. One such example is the mud
33
pumps and the selection and maintenance of liners. All too often a rig manager will save money by
installing cheap steel liners that are less erosion resistant and will wash out rapidly if solids are high in a
mud system instead of paying for more expensive ceramic liners. Pumps have many sealing parts and
lack of a maintenance program often leads to leaks, loss of efficiency and eventually total washouts
resulting in costly down time. Purchasing the right parts for the job and maintaining the equipment is
essential to avoiding NPT and efficiency loss.
4.3.2.4. Elimination of Drilling Waste
Each sub-assembly of drilling process reviewed in the workshop was evaluated for the 7 types of waste.
The 7 types of waste, are defects, waiting, inventory, transportation, excess motion, over-production
and lastly over-processing which typically inundate most drilling operations to varying degrees. Some
are easily recognized through data and simple observation while some are less apparent and might
require recognition through a lean trained expert. The following are examples of the 7 types of that are
common in drilling operations and possible solutions.
Fig. 15 - 7 types of waste (Leanguru.pro 2014).
Defects
Defects unfortunately are all too frequent in drilling operations but most are easily identified through
equipment failures and can be fixed before continuing on with operations. Most defects result in NPT
unless they can be fixed offline and range from the simple replacement of parts to excessive down time
that can require multiple days to restore the problem. One of the most common defects are failed mud
motors and MWD packages which in most cases require a trip out of the hole to replace the equipment.
34
Depending on hole depth and wellbore conditions, tripping operations can result in over a day of down
time.
Some defects in contrast are not obvious during the drilling process and can cause well integrity issues
for drilling’s customers, the completions group and the production group. One of the most costly
defects passed onto the customer are production strings with compromised pressure ratings that
prevent the well from being stimulated. Work-overs to fix casing issues usually range from hundreds of
thousands of dollars to total loss of the well and millions of dollars for plug and abandonment
operations and redrilling of the well.
Solution
Developing a close relationship with suppliers is imperative to identifying defects, determining the root
causes of the defects and performing corrective actions to ensure the problems do not reoccur. If the
occurrence of a certain defect is low and the time associated with correcting the issue is also low, then
pursuing a corrective measure may be of low priority. If the occurrence is high and time associated with
correcting the defect is low or the occurrence is infrequent but the time associated with correcting the
defect is extensive, then medium priority should be given to the problem. Defects that are frequent and
with corrective actions that are lengthy in duration should be first priority.
A Pareto Diagram is a Lean tool that plots frequency and time associated with defects to visually display
the significance of a problem. The chart is organized with the most severe problem closest to the Y-axis
in descending order to the least significant problem. Priority should be given to the left most defect. As
one problem is resolved, the next problem in sequence should become the primary focus.
Third party inspection services for critical equipment during or post manufacturing is a preventative
measure that reduces the amount of defects that work their way into the well construction process. An
example of inspection services widely used in the industry are in-mill inspections of casing strings. The
benefits of inspection services and the corresponding costs far outweigh the costs associated with work-
overs remediating the failed equipment after installation in the well.
Waiting
Most waste associated with waiting can be tied to poor and inadequate planning. Many service
providers in drilling operations must travel to the rig site to perform their duties. Cementing is an
example of a service that is often exposed to waiting. If the cementing company is not provided with a
timely enough notice, the rig has to shut down and cannot continue with operations until the casing
string is cemented in place. If the rig provides the cement company with too early of a notice, then the
cement company charges the operator costly stand-by time.
Depending on the location of drilling operations in the US, the replacement of specialized equipment is
often associated with multiple days lost to waiting as the parts are ordered and flown in or trucked from
35
across the country. The company’s operations that this thesis is based on are located in North Dakota
where most service companies’ warehouses and manufacturing facilities are located in the southern
states. Extended periods of NPT waiting on parts has occurred on occasion.
Solution
Proper planning is as important in drilling operations as it is in any well run business. A look forward at
upcoming operations and establishing standard milestones for calling out of services will minimize waste
associated with waiting. Certain challenges exist for requesting services that are dependent on the
completion of a prior process especially if the process is at the mercy of hole conditions. Cementing
service providers often experience delays since they cannot start operations before the casing is on
bottom. Multiple variables can contribute to casing running issues and excessive drag such as wellbore
tortuosity, toe-up vs toe-down horizontals, high low-gravity solids in the mud and high plastic viscosities
increasing wellbore friction, cuttings beds, etc. and can cause delays of several hours due to reduced
casing running speeds. Each one of the variables mentioned represent issues that should be understood
with the drilling process designed to minimize their effects.
The service providers should have an intimate understanding of their equipment and should maintain
spare parts as necessary to prevent costly delays associated with ordering and shipping. They should
know the frequency of failures of their equipment, which components are most prone to failure and
maintain inventory volumes of replacement parts within a storage facility nearby the drilling operations.
Just as operators should establish good relationships with their service companies, service companies
themselves are customers relying on quality raw materials or products from suppliers and should also
maintain good working relationships and open communication.
Inventory
Though excessive inventories do not cause the same problems as the buildup of buffer stocks and
finished products in warehouses, inventory waste in drilling causes problems in other ways that are less
apparent but not to be overlooked. If an excessive inventory of equipment and parts is kept with the
rig, valuable time is lost during the mobilization phase since trucking space is consumed and additional
loads are required. A build-up of equipment that is never used is also quite common on rigs over time
and usually ends up stashed in the corners of the pad taking up valuable space leading to tight locations,
decreased mobility and increased HSE risk.
Solution
The rig crews and drill site supervisors should perform regular walk around assessments of the rig site to
determine what is required and regularly used for operations and what is not. It is easy to overlook
equipment that has taken up permanent residency with the rig. All of the excess equipment should be
removed. Equipment that is used but only on occasion should be removed from the rig site if it can be
36
provided through a call out on an as needed basis. Applying Lean’s principle of 5S can assist in the
process of sorting through wasteful inventories. 5S will be discussed in depth later on in this write-up.
Transportation
Transportation waste is found in most drilling operations and is mostly associated with the layout of rig-
site equipment and the storage of tools. Optimization of the layout of equipment is often disregarded
with parts and tools located in inconvenient locations that require trips up or down the steps to the rig
floor or across the rig site. Time wasted to transportation at the rig may not be as obvious as time lost
to a defect but builds up quickly and can mean the difference of hours in the total drilling process.
Solution
Optimizing the layout of rig site equipment should be just as important as moving the rig in a timely
matter. Often this part of a move is neglected and equipment is left where it is dropped off causing
undue time for the retrieval of tools, part and equipment. Understanding where the equipment will be
used the most and placing it within close vicinity of that location is key. Further optimization of
equipment layout may also warrant the addition of smaller toolboxes that can be placed a few feet from
where the tools are used. One example is adding a toolbox with tools for nippling up BOPs in the subs
below the rig floor. The philosophy of 5S also applies for the layout of equipment.
Motion
Different from Transportation, excessive Motion is time wasted due to unnecessary movements or poor
placement of tools within a station. An example of waste associated with motion is found during
connections and the rig crews’ preparedness and placement of the tools required for the job such as
slips, the pipe dope bucket and brush, and the floor hands stabbing the pipe in the connection. Other
wasted motion on the connection can be caused by the driller and where he sets the drill pipe in the
slips in reference to the tool joints position above the rig floor. If the pipe is set too high or low, then
make up / break out of the connection with the iron roughneck is not possible and the pipe has to be
lifted out of the slips and repositioned.
Solution
Observe the positioning of the floor hands, their equipment and their efficiency of movement. If
permissible by the drilling contractor, record a video of the connection to review with the rig crew and
ask them what they can do better. Supply connection performance data from other rigs to establish
benchmarks while stressing not to hurry at the risk of exposing the rig personnel to increased safety
risks. As the military adage goes “Slow is smooth, smooth is fast”.
37
Over-processing
Over-processing is doing more than is required for the job at hand. A perfect example in drilling is
reaming after the drilling of each stand. On occasions reaming may be warranted as a result of
deteriorating hole conditions or insufficient cuttings lift but usually it is not as the properties of the mud,
flow rate available during drilling, regular sweeps and rotation of the pipe provide all of the required
hole cleaning mechanisms to prevent a stuck pipe situation.
Solution
Monitor the conditions of the hole using the rig’s Electronic Drilling Recorder to limit reaming on an as
needed basis. Early signs of hole cleaning issues or wellbore instability will become recognizable
through increases in the circulating pressure, pick-up and slack of weights trending higher or lower than
expected respectively, sudden spikes in bit weight and increasing torque values and will provide the
driller the necessary information to limit reaming operations to only on an as needed basis.
Over-production
Over-production is the waste of creating more of a product than is necessary. An example of over-
production in drilling is the volume maintenance of mud inventories, particularly oil-based which cannot
be disposed of in a reserve pit. The build-up of low gravity solids will cause increased friction factors
resulting in hole drag and poor weight transfer while drilling in horizontal wells. To maintain low gravity
solids percentages at acceptable levels, base oil is added to dilute the system or the system is processed
through solids removal equipment. If dilution is the primary method for solids control and outpaces the
typical losses to cuttings, volumes will increase and can become a problem if pit capacity is limited
resulting in costly handling and storage logistics.
Solution
A steady state balance needs to be struck between the usage of solids removal equipment and dilution
rates to maintain properties at acceptable levels instead of solely depending on dilution. The mud
company and the solids control company need to establish a close relationship where there is open
communication regarding proper controlling of solids.
4.3.2.5. Non-Productive Time and Root Cause Analysis
During the WTCRW it was determined that a further analysis of NPT was warranted. The most common
Non-Productive time results from equipment failures whether on the surface or downhole, rig
equipment or 3rd party. Inherently, failures that occur downhole have a larger impact on rig efficiency
due to the fact that most will require a replacement trip that can take from only a few hours to more
than a day depending on the hole depth and conditions of the well. Therefore it is critical that any
38
component of the drill string passes a strenuous inspection process for quality and either has limited
prior run hours or has been refurbished to a near new state. Should any of these steps be neglected, an
operator is at increased risk of costly NPT. It is much cheaper to prevent a problem proactively than to
fix a problem after it has occurred with all inclusive rig spread rates ranging from $2,500 to $3,750 per
hour in a typical drilling scenario.
To determine the frequency and severity of equipment failures, lean makes use of Pareto Diagrams.
Pareto Diagrams are bar graphs with the bars representing either a summation of cost, either time or
money, or a count of events arranged in descending order. The first bar represents the most prevalent
equipment failure and should be prioritized as the first item to address. Once the issue has been
resolved, the subsequent bar becomes the next priority for corrective actions.
One method for assisting in the determination the root cause of a failure is a Fishbone Diagram, or
Ishikawa diagram as it is referred to in Lean. The diagram breaks the possible causes in into categories,
e.g. Man, Machine, Method and Material, which all lead to an effect. Other cause categories can be
added to the diagram as necessary to perform a proper analysis. Fig. 16 is an Ishikawa Diagram that was
created to analyze what the potential causes were of slow Rate Of Penetration (ROP) on a well. Once
the analysis was fully conducted, it was determined that the elastomer was not rated to the
temperature of the well and was therefore weakened and eventually led to a motor failure.
Fig. 16 - Ishikawa diagram for slow ROP
In an analysis of the operator’s NPT for the second half of the year of 2015, the main offenders of
downtime were easy to distinguish. Fig. 17 is the Pareto Diagram of the analysis.
39
Fig. 17 - Sum of downtime, top; count of downtime events, bottom
In Fig. 17, the graph on the on top is the sum of days associated with NPT whereas the graph on the
bottom is the count of downtime events distributed by category. Based on the Pareto Diagram on the
top, the majority of NPT is a result of issues associated with directional drilling equipment failures. The
impact is very significant for a four rig drilling fleet. Just under 35 days of downtime were associated
with directional drilling issues. With the average drilling days (spud to release) down to 15.7 days in
2015, a complete elimination of this downtime would result in two additional wells for the second half
of the year.
40
When comparing the two graphs, the sum of days vs the frequency of the events, it can be observed
that the time associated with non-productive issues does not correlate with the number of occurrences.
What this implies is that though an event may happen less frequently, the time loss may be of much
greater impact. In the graph at the bottom of Fig. 17, the rig downtime events led the group in count.
Time lost associated with the rig is much less however and places the associated rig related issues in 3rd
for time lost. The primary reason that directional drilling NPT dominates the group is that with the
majority of failures, a trip is required if surface trouble shooting efforts are unsuccessful. This category
is also further populated by time lost to sidetracking in the event that build-rates are inadequate to land
the well within the target zone or if one of the troublesome shales is penetrated should geo-steering
interpretations be off or a loss of directional control occur. Bit issues also require replacement trips
which is why it comes in second in the NPT category.
Based on the information in the graphs, the leading issues can be targeted and broken down on a finer
scale to hone in on category specific problems. Fig. 18 are the graphs of the directional drilling problems
and Fig. 20 are rig related issues. The majority of NPT related to bit replacements are a result of
premature dulling of the cutters which, based on the extensive development and design iterations of
the bits made specifically for the Bakken, are usually caused by mismanagement of drilling parameters.
For this reason, the bit replacement category has been excluded from breaking down to a finer level for
this paper. A close collaborative relationship with bit vendors and extensive dull analyses can accelerate
the design curve in new areas. Developing a method for monitoring and reviewing drilling parameters
will also help reduce downtime associated with bit dulling issues.
41
Directional Drilling Related NPT
Fig. 18 - Sum of directional drilling downtime, top; count of directional drilling downtime events, bottom
When broken down into sub-categories, the directional drilling related issues are still dominated by
problems that require a trip out of the hole. This highlights the criticality of having the highest quality
downhole directional drilling equipment. The motor and MWD equipment are exposed to an
environment with high torques, high axial loads, high differential pressures, high intensity vibrations,
high temperatures and abrasive solids moving at high velocities. Given that the directional BHA
42
components have to perform under such extreme conditions, it is not surprising that this is most
reoccurring culprit of downtime. Dependence on the service provider to use parts that have enhanced
engineering designs, normally associated with higher costs, will improve reliability and mean time
between failures. Even with the high failure rate, the directional drilling contractor used by the operator
leads the industry in Mean Time Between Failures (MTBF), a KPI used to determine the frequency of
failures. Anytime a problem does occur, the directional drilling company provides the operator with an
in-depth tear down report. The tear down is a post failure inspection to determine the root cause.
What is promising is that the majority of the failures can usually be traced back to a controllable root
cause allowing for corrective measures to be incorporated in the design and assembly process thus
permitting continuous improvements to the MTBF metric. Commonly when the directional motor fails,
the reason is due to the motor being run out of spec through a mismanagement of parameters. It is
important to success that the rig crews understand the importance of balancing penetration rates with
maintaining down hole equipment within their limits. It is still all too common that a rig will aim for
running the most extreme parameters to maximize ROP with the anticipation that something will
eventually fail but they can quickly trip for a replacement. Not only does this expose the crews to
increased safety risks associated with the additional handling of the drill string and BHA, rarely does this
method outperform steady on bottom drilling to the section TD.
In Fig. 18 MWD issues lead the count in failures but not time. The reason for this is that MWD problems
can sometimes be resolved from surface through troubleshooting methods. The MWD subcategory also
includes anytime associated with re-logging of an interval if gamma readings were poor over a depth
interval. The majority of MWD failures are caused by high vibrations, e.g. stick-slip, whirl, lateral and
axial vibrations. High vibrations can be a result of poor BHA design, parameters mismanagement,
formation or inadequate hole cleaning. Noisy bits that are too aggressive for the formation are one of
the leading reasons for high vibrations resulting in a failed MWD. Multiple iterations of bit designs have
improved the vibrational noise level while maintaining high penetration rates and reliable durability.
Categorizing the failures by hole section, Fig. 19, shows that the majority of Mud Motor and MWD
problems occur in the production hole. This can be attributed to the high differential loads that are
used for drilling in the lateral with the slim hole tools being less resilient than the larger tool sizes. The
failure count for the intermediate and the production hole are similar but the length of time required to
trip out of the lateral is what causes the prolonging of time.
43
Fig. 19 - Motor and MWD failures by hole section.
When a failure report is generated, it is important that the drilling engineer takes the time to
understand what the cause of the failure is and holds the directional company accountable for taking
the necessary corrective measures should the failure be related to their equipment. The operator
should also be embracive to feedback if the cause of the failure was mismanagement of parameters at
which time he should inform the drill site supervisor.
In the beginning of the operator’s drilling in the Williston Basin, the downtime associated with
directional control issues and shale strike issues were much more frequent and costly. The control
issues primarily were localized to the curve where build rates would be inadequate to land within the
geology determined target zone. After multiple design iterations of the BHA, it was determined that the
motors provided by the directional drilling contractor were the reason for the build rate issues. The
solution was to source the curve motors from a 3rd party which reduced the frequency of trips for more
aggressive build assemblies.
Shale strikes reduced in frequency with time as the geo-steering team became more familiar with the
gamma markers and as more wells were drilled providing enhanced control when drilling development
offsets. Clear communication between the drilling group and the geo-steering group also improved the
frequency of shale strikes. The geo-steerers were unaware that drilling in one part of the target zone
would subject the BHA to hard chert stringers that would cause uncontrollable deflections upwards into
the shale resulting in the need for a sidetrack. Once the geology group was made aware that drilling
within what was thought to be the “sweet spot” was causing the high frequency of shale strikes, they
agreed to lower their targets thus reducing shale strikes dramatically.
44
Rig Related NPT
Fig. 20 - Sum of rig related downtime, top; count of rig related downtime events, bottom.
The rig related downtime category is any time lost due to equipment failures or rig crew errors.
Fortunately for the rigs that were analyzed, rig crew errors are seldom and usually not very severe. This
usually is not the case when a rig crew is inexperienced or has not been working together for an
extended period of time. The group is dominated by a wide margin by Top Drive issues which puts it at
the top of the list for problems to resolve. Since the Top Drive is a complex machine with several
working mechanisms that serve specific purposes e.g. the gear box and drilling motor which transmits
45
rotary motion and torque to the drill pipe, and the swivel, a bearing assembly which allows for the
transfer of rotating loads to the lifting components, etc. , it needs to be further broken down to
determine which components are failing.
Fig. 21 - Top drive specific NPT time, top; top drive specific NPT events count, bottom.
46
Based on the Pareto Diagram, a total replacement of the Top Drive is very costly resulting in over a day
of NPT but rarely occurs. Proper maintenance of the Top Drive and frequent inspections will
dramatically reduce the probability of a catastrophic failure requiring a full replacement. Failure of the
blower motor will also result in a significant amount of time lost but is also infrequent. The two leading
causes of NPT are washpipe packing leaks and losses of communication or electrical issues. The main
factors that affect washpipe packing life are standpipe pressure, top drive revolutions per minute, the
washpipe diameter and mud temperature (Varco Systems 2004). Varco recommends grease injections
at a minimum on a daily basis as preventative maintenance. Failure to follow recommended lubrication
schedules will accelerate the wear of Top Drive components. Fig. 22 is a Lubrication and Maintenance
guide for a TDS-11SA showing all points of injection for the grease as well as the frequency of injections.
47
Fig. 22 - TDS -11SA Lubrication and Maintenance Guide (Varco Systems 2016).
To further determine what may be the reason for the NPT associated with the washpipe packing, the
maintenance records should be checked to ensure that proper grease injection schedules are being
followed. It may be possible to swap the sealing elements to a higher grade material should failures
remain a problem even with proper preventative maintenance. When the problems are broken out by
rig (Table 5), it can be seen that all experienced downtime associated with washpipe packing leaks.
48
Table 5 - Count of NPT events associated washpipe packing leaks.
One approach to mitigating the downtime associated with washpipe packing failures can be to take a
proactive maintenance approach and replace the washpipe packing offline while the while the rig is
moving from one well to the next.
4.3.2.6. Total Productive Maintenance
The frequency of equipment failures resulting in NPT can be improved by establishing a Total Productive
Maintenance (TPM) program. TPM improves the maintenance practices for equipment and
infrastructure, and enables the prediction and/or prevention of anticipated failure. TPM aims to remove
deficiencies from machines to minimize or eliminate defects and downtime. According to the
publication by Munro et al. (2015) TPM addresses inefficiencies in the following manner.
Avoiding reduced, idled, or stopped performance due to equipment breakdown.
Reducing and minimizing the time spent on setup and changeover of equipment, which can
otherwise idle machine operations and create bottlenecks.
Avoiding stoppages arising from the processing or discovery of unacceptable products or
services.
Ensuring that processes and equipment are operating at the speed and pace for which they
were designed. If the pace is slower or delayed, work to address and rectify the source of the
delays.
Increase the yield of acceptable material to reduce material waste, scrap, rework, and the need
for material reviews.
As in the case with the issues with the washpipe packing discussed above, any time there is a leak,
operations have to be stopped and the component replaced. Though this can be taken care of in less
than 30 minutes, the issue is so frequent that it builds to become a much greater problem but is often
overlooked as a source of downtime. Following a TPM for the top drive and its components is essential
to limiting the downtime which would otherwise be much more prevalent.
A drilling rig is subjected to extreme operating conditions and without a proper maintenance program
will experience frequent NPT that can be costly to both the contractor and the operator. Since the
drilling contractor is responsible for maintaining the rig equipment, drilling contracts allow for shutting
down of operations for half an hour to a full hour per day for servicing the equipment without
penalization. This is an example of TPM for the rig which includes the maintenance of the top drive. If
an equipment failure leads to downtime in excess of a contracted amount, the operator is no longer
liable for payment of the rig rate until the equipment has been repaired and normal operations can
Revised NPT Category Rig Failed Component - Failure Type Count of Events
Rig-Surface Eq. Issue-Top drive Nabors B13 Packing/Seal Leak 2
Nabors B14 Packing/Seal Leak 3
Nabors B24 Packing/Seal Leak 3
Sidewinder 104 Packing/Seal Leak 2
49
resume. Therefore it is in both parties best interest to strictly adhere to the TPM established for
maintaining the rig.
Since the rig is the primary and most costly tool used for the drilling process, the alliance with the
drilling contractor is extremely important to ensure that quality of the equipment is maintained and that
they are invested in the quest for perfection. Regular service quality meetings should be held with the
drilling contractor to discuss successes as well as performance and equipment gaps that were
experienced over the prior period. Corrective actions should then be established to address the issues
in an effort to eliminate them from future occurrences striving for continuous improvement.
4.3.2.7. 5S
5S is a Lean organization concept that makes use of 5 steps to achieve order at the work place. The 5
steps are the following.
Sort – Sort out the necessary items required for a work station and remove those that are not
needed.
Straighten – Organize the work station in logical arrangements so that they are easily and
readily used.
Shine – Keep the work station clean. A tidy work station makes identification of defects easier.
Standardize – Use the first three steps regularly to maintain the condition of the work station.
Sustain – Rely on the steps to sustain the organization of the workshop.
Maintaining a regimental 5S discipline will significantly improve working conditions at the rig both from
an equipment perspective but also an HSE perspective. The rig can be a very chaotic and dirty
workplace given normal operating conditions. Oil based muds and grease that are a normal part of
operations will adhere to rig equipment and personnel which can potentially lead to dangerous working
conditions but also to the concealment of impending defects. Sorting and straightening of rig
equipment and cleaning on a regular basis should be part of the normal daily work flow on the rig.
During a visit to the rigs, a 5S analysis was performed by the operator to improve organization. The
following observations were made.
Unorganized tool storage containers (Fig. 23). Time was often wasted trying to find an item in
the container. Excessive tools and replacement parts not required for the job could be found in
the container.
50
Fig. 23 - Unorganized tool storage container
Tool stations were not straightened in any logical order (Fig. 24). Finding the right sized tool
often meant pulling several tools off the rack and sorting through them.
Fig. 24 - Unorganized wrench tool station.
Excess drill collars that had not been used in years located on the pipe storage racks
Varying numbers of fluids storage tanks across rig fleet
Damaged hoses needing to be disposed of stashed in open top containers
These items were addressed with the drilling contractor to initiate 5S organization at the rig. Once
implemented, job times decreased because of the elimination of searching for tools and parts, rig move
times decreased because of the elimination of unnecessary trucking loads, and rental costs decreased by
51
releasing excessive equipment that was being charged to the operator. The crews also started
maintaining their rigs in cleaner condition as time was freed up not having to search for items.
4.3.2.8. Mistake Proofing (Poka Yoke)
Mistake proofing, or Poka Yoke as it is referred to in Lean, is the concept of assisting an operator in
avoiding mistakes. Many drilling rigs incorporate mistake proofing to varying degrees, in particular
modern day computerized AC (Alternating Current) rigs. Critical rig functions that are controlled on the
driller’s dashboard often require an override before being able to engage/dis-engage associated
equipment. Fig. 25 is an example of a Poka Yoke check that would prevent the driller from releasing a
string of casing unless absolutely certain this was the course of action he wanted to take.
Fig. 25 – Driller’s control dashboard displaying casing release override.
Further opportunity for mistake proofing exists beyond just the computerized controls of the rig. Color
coding or labeling the BOP hydraulic lines in Fig. 26 is an opportunity for mistake proofing and would
assist in properly connecting the hoses to the correct BOP components.
52
Fig. 26 – Accumulator hydraulic hoses.
Incorporating Poka Yoke at the rig and into the drilling process as much as possible, where applicable,
will improve efficiency through the elimination of downtime associated with corrective measures for
frequently made mistakes.
4.3.2.9. Results from WTCRW II
Going into the second workshop, a certain level of skepticism hung in the air over what could really be
achieved since the operator felt that most of the low hanging fruit had been picked. During the
workshop, it quickly became apparent that there was a substantial amount of room for improvement
through further incorporation of lean concepts. A few of the attendees of the workshop from other
functional groups were trained in lean and helped drive the direction of which concepts to use in certain
situations. After the workshop, the lean initiatives were handed over to the drilling group which had a
mixed background of exposure to Lean but no one with any formal training. Some of the concepts
would have to be learned through self-education.
Similar to the first workshop, the leading indicator of success would be reflected in the drilling days.
One difference in this case was that the operator used total days on location instead of Spud-to-Release
days to encompass rig move efficiency. Fig. 27 is a graph of days on location from 2014 up through
March 2016.
53
Fig. 27 - Drilling days on location.
In the graph above, it can be observed that in the subsequent months after the workshop, the operator
had its best months of drilling performance delivery it had yet achieved. At the same time that drilling
efficiency was improving, oil price remained at a near historical low which forced the operator to cut
back its operations down to one rig. The story was the same for all operators in the Williston Basin
which in turn forced the drilling contractor to reduce personnel as a widespread stacking of rig took
place. In doing so, many of the seasoned rig personnel that had risen through the ranks were demoted
in effort to keep the most qualified employed. Several of the tool pushers that were demoted to drillers
had never operated a modern day AC rigs and were only familiar with drilling with DC (Direct Current)
rigs with break handles. Though the concepts were the same, the modern technology made operating
the rig drastically different from what they were familiar with. The increase in days shown in Fig. 27 for
December 2015 is a direct reflection of the impact the changeover of personnel had on rig efficiency.
4.3.2.10. Lessons Learned from Workshop II
Some of the lessons that were learned from the first workshop paved the way for a much easier second
workshop and corresponding incorporation of changes. Some of the new lessons that were learned
were the following:
Searching for waste later in the field development cycle requires increased effort to identify
opportunity
Though it requires more work, ample opportunity exists even within a mature drilling program
Personnel turnover has a significant impact on performance
54
Even with a daily quality checking regiment by the engineers, drilling reports are still prone to
mistakes associated with human error
5. Conclusion
As is the case with most industries, lean has its place in oil and gas and can be used to successfully
improve efficiency and reduce costs. A hand-full of oil and gas companies, both operators and
service/equipment providers alike, have successfully used lean to improve their operations. Operators
have used lean to reduce the time and costs for the well construction process while service providers
have used lean to improve the manufacturing process of equipment and tools. Equipment providers’
operations are more in line with the conventional model of factory manufacturing that lean was
founded on compared to the well construction process since production usually occurs along an
assembly line.
Since 2013 the operator discussed in this paper has relentlessly pursued efficiency improvements in
effort to deliver quality wells on-schedule at reduced costs. This has primarily been out of necessity to
improve well economics, especially in the time of depressed oil prices, but also as a result of the desire
to be a best-in-class company. Some of the improvements realized resulted from progressing through a
typical learning curve associated with any field and refining the standard operating process while others
have been accomplished through the application of improvement initiatives, in particular through the
use of lean and the elimination of waste.
The operator’s journey with lean has been in progress for nearly three years and has experienced
several challenges along the way. The operator has managed to overcome acceptance barriers that
were initially in place and, as the drilling team, both in the office and in the field, have grown
comfortable with change, the pursuit of perfection has become easier.
The drilling process of a well requires an alteration to the conventional manufacturing model of a
product being passed along from station to station in an assembly line, to account for a stationary
product with the work assemblies as the moving component. Counter to the lean concept of continuous
flow, batch-and-queue has its advantages on a multi-well pad drilling scenario such as the operator’s in
the Williston Basin.
Data integrity is crucial to being able to conduct a proper analysis of drilling performance and should be
a part of any improvement initiative where quality may be lacking. The daily drilling report data can be
used on a large scale to identify areas for improvement but shouldn’t be used to perform too granular of
a performance analysis. Grouping sub-assemblies into logical cells with common goals allows for easier
management of activities on a more meaningful scale when using the daily drilling report data. The use
of a drilling state detection service that is fed off of sensor data is the most reliable source of drilling
performance data and can be used for a to-the-second level of analysis.
55
For the drilling process, this paper explored the following Lean tools which have been used by the
operator to improve well delivery.
SMED
5S
TPM
Continuous Improvement
Pareto Diagrams
Root Cause Analysis (Ishikawa Diagrams)
7 Types of Waste
KPIs
Mistake Proofing (Poka Yoke)
Only the surface has been scratched in what is achievable through the implementation of Lean. A
deeper reach into the Lean tool box will aid in the continued effort to further eliminate waste and
pursue drilling process perfection.
56
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List of Acronyms
NPT – Non-productive Time ISO - International Standardization Organization TPS - Toyota Production System JIT – Just In Time SMED - Single-Minute Exchange of Dies TVD - True Vertical Depth MD – Measured Depth KOP – Kick Off Point TD – Target Depth BHA – Bottom Hole Assembly WTCRW – Well Time and Cost Reduction Workshop BDP – Best Demonstrated Performance BOP – Blow Out Preventers MWD – Measurement While Drilling KPI – Key Performance Indicator ROP – Rate of Penetration MTBF – Mean Time Between Failures AC – Alternating Current DC – Direct Current